Third Coast Midstream (AMID) SC 13E3 Going private transaction

Exhibit (c)(9)

Preliminary Draft Subject to Change Discussion Materials Prepared for The Conflicts Committee of the Board of Directors of American Midstream GP, LLC March 11, 2019 Preliminary Draft Subject to Change These materials have been prepared by Evercore Group L.L.C. (“Evercore”) for the Conflicts Committee of the Board of Directors of American Midstream GP, LLC (the “Conflicts Committee”), the general partner of American Midstream Partners, L.P., to whom such materials are directly addressed and delivered and may not be used or relied upon for any purpose other than as specifically contemplated by a written agreement with Evercore. These materials are based on information provided by or on behalf of the Conflicts Committee, from public sources or otherwise reviewed by Evercore. Evercore assumes no responsibility for independent investigation or verification of such information and has relied on such information being complete and accurate in all material respects. To the extent such information includes estimates and forecasts of future financial performance prepared by or reviewed with the management of the Partnership and/or other potential transaction participants or obtained from public sources, Evercore has assumed that such estimates and forecasts have been reasonably prepared on bases reflecting the best currently available estimates and judgments of such management (or, with respect to estimates and forecasts obtained from public sources, represent reasonable estimates). No representation or warranty, express or implied, is made as to the accuracy or completeness of such information and nothing contained herein is, or shall be relied upon as, a representation, whether as to the past, the present or the future. These materials were designed for use by specific persons familiar with the business and affairs of the Partnership. These materials are not intended to provide the sole basis for evaluating, and should not be considered a recommendation with respect to, any transaction or other matter. These materials have been developed by and are proprietary to Evercore and were prepared for the benefit and internal use of the Conflicts Committee. These materials were compiled on a confidential basis for use by the Conflicts Committee and not with a view to public disclosure or filing thereof under state or federal securities laws, and may not be reproduced, disseminated, quoted or referred to, in whole or in part, without the prior written consent of Evercore. These materials do not constitute an offer or solicitation to sell or purchase any securities and are not a commitment by Evercore or any of its affiliates to provide or arrange any financing for any transaction or to purchase any security in connection therewith. Evercore assumes no obligation to update or otherwise revise these materials. These materials may not reflect information known to other professionals in other business areas of Evercore and its affiliates. Evercore and its affiliates do not provide legal, accounting or tax advice. Accordingly, any statements contained herein as to tax matters were neither written nor intended by Evercore or its affiliates to be used and cannot be used by any taxpayer for the purpose of avoiding tax penalties that may be imposed on such taxpayer. Each person should seek legal, accounting and tax advice based on his, her or its particular circumstances from independent advisors regarding the impact of the transactions or matters described herein.

Preliminary Draft Subject to Change Table of Contents Section Executive Summary I Situation Analysis II Asset Overview III AMID Financial Projections IV Preliminary Valuation V Illustrative AMID Unitholder Tax Analysis VI Appendix A. Weighted Average Cost of Capital B. Detailed Segment Financial Projections C. Preliminary Valuation of Natural Gas Gathering & Processing D. Preliminary Valuation of Natural Gas Transportation E. Preliminary Valuation of Offshore Pipelines (Excl. Delta House) F. Preliminary Valuation of Delta House G. Preliminary Valuation of Bakken Crude Oil Gathering H. Preliminary Valuation of Silver Dollar Pipeline I. Preliminary Valuation of Cushing Terminal J. Preliminary Valuation of NGL JV Interests K. Preliminary Valuation of AMID Corporate G&A Expenses Preliminary Draft Subject to Change I. Executive Summary

Preliminary Draft Subject to Change Executive Summary Introduction Evercore Group L.L.C. (“Evercore”) is pleased to provide the materials herein to the Conflicts Committee (the “Conflicts Committee”) of the Board of Directors of American Midstream GP, LLC (the “General Partner”), the general partner of American Midstream Partners, LP (“AMID” or the “Partnership”), regarding the proposed acquisition by the General Partner, a subsidiary of ArcLight Energy Partners Fund V, L.P. (“ArcLight”), of all common units representing limited partner interests in AMID (each, a “Common Unit”) from the holders of such units other than Common Units held by ArcLight, the General Partner or their respective affiliates (the “Merger”) ArcLight currently owns 40,735,962 Common Units on an as-converted basis1 (52.0% of the total outstanding Common Units2) and ArcLight owns the 1.2% general partner interest in AMID through the General Partner, ArcLight’s wholly-owned subsidiary In its September 27, 2018 offer letter (the “Initial Proposal”), ArcLight proposed to acquire each outstanding publicly-held Common Unit for $6.10 in cash (the “Initial Offer”) In its January 2, 2019 offer letter (the “Second Proposal”), ArcLight proposed to acquire each outstanding publicly-held Common Unit for $4.50 in cash (the “Second Proposal Consideration”) On February 1, 2019, ArcLight revised its offer proposing to acquire each outstanding publicly-held Common Unit for $4.85 in cash (the “Third Proposal Consideration”) On February 19, 2019, ArcLight revised its offer proposing to acquire each outstanding publicly-held Common Unit for $5.25 in cash (the “Consideration”) The Consideration represents a 66.7% premium to AMID’s closing unit price as of January 3, 2019 prior to the announcement of the Second Proposal and a 36.7% premium to AMID’s closing unit price as of March 7, 2019 The Merger, pursuant to the Agreement and Plan of Merger by and among [Merger Sub LLC], the Partnership and the General Partner (the “Merger Agreement”), is to be structured as a merger between the Partnership and Merger Sub LLC with the Partnership surviving the merger, and requires approval by the Conflicts Committee, the ArcLight Investment Committee and the holders of a majority of the outstanding Common Units on an as-converted basis Source: Public filings 1. Represents 7,940,322 Series A-l Convertible Preferred Units (“Series A-1 Units”) held by High Point Infrastructure Partners, LLC (“High Point”), convertible into 10,172,347 common units of AMID (“Common Units”), which are indirectly owned by Magnolia Infrastructure Partners, LLC (“Magnolia”), 3,401,875 Series A-2 Convertible Preferred Units (“Series A-2 Units”) held by Magnolia, convertible into 4,358,142 Common Units, 9,514,330 Series C Convertible Preferred Units (“Series C Units”) held by Magnolia Infrastructure Holdings, LLC (“Magnolia Holdings”), convertible into 9,527,650 Common Units, 1,291,869 Common Units issuable upon exercise of the warrant issued to Magnolia Holdings by American Midstream Partners, LP, dated April 25, 2016, 10,563,942 Common Units held by Magnolia Holdings, 1,349,609 Common Units held by American Midstream GP, LLC, which is approximately 77% owned by High Point and approximately 23% owned by AMID GP Holdings, LLC, which is approximately 93% owned by Magnolia Holdings, 618,921 Common Units held by Magnolia and 2,853,482 Common Units held by Busbar II, LLC, an affiliate of ArcLight 2. Assumes inclusion of the units issuable upon exercise of the warrant issued to Magnolia Holdings dated April 25, 2016; exclusion of these units results in adjusted ownership on an as-converted basis of 51.2% 1 Preliminary Draft Subject to Change Executive Summary Overview of Materials The materials herein include: An executive summary, including: (i) an overview of the Merger detailing summary proposed terms; (ii) a comparison of the financial projections for AMID as provided by AMID (the “AMID Financial Projections”) with the financial projections for AMID reviewed at the February 5, 2019 Conflicts Committee Meeting (the “February 5 Meeting”); (iii) a summary of the primary drivers impacting the AMID financial projections relative to the financial projections reviewed at the February 5 Meeting; (iv) changes in Evercore’s analysis of the Proposed Transaction since the February 5 Meeting; (v) an overview of AMID’s current summary organizational structure and (vi) an analysis of financial metrics implied by the Merger An overview of AMID’s current market situation An overview of AMID’s assets by business segment A review of AMID Financial Projections and a review of the assumptions utilized by AMID management in deriving such financial projections A preliminary valuation of AMID An illustrative review of the potential cash tax impact to unaffiliated unitholders resulting from the Merger 2

Preliminary Draft Subject to Change Executive Summary Overview of the Merger Evercore has been asked by the Conflicts Committee, whether, in Evercore’s opinion, as of the date of the Opinion opinion, the Consideration is fair, from a financial point of view, to the unaffiliated common unitholders of Requested: the Partnership American Midstream Partners, LP Counterparties American Midstream GP, LLC, a subsidiary of ArcLight Energy Partners Fund V, L.P. and the general partner of American Midstream Partners, LP ArcLight to acquire all publicly-owned Common Units from the holders of such units other than Merger Common Units held by ArcLight, the General Partner or their respective affiliates Summary AMID will cease to be a publicly-traded partnership Common Unit holders other than ArcLight, the General Partner and their respective affiliates Consideration (“Unaffiliated Unitholders”) will receive $5.25 in cash for each AMID common unit held Approval of the Conflicts Committee Requires approval from 50.0% of Common Unit unitholders on an as-converted basis (affiliates of Timing and Approvals ArcLight currently own 52.0% of LP units on an as-converted basis) HSR approval The Merger is expected to close in Q2 2019 assuming all required approvals are obtained Other The Merger is structured to be taxable to the Unaffiliated Unitholders 3 Preliminary Draft Subject to Change Executive Summary AMID Financial Projections Comparison ($ in millions) February 5 Meeting AMID Financial Projections Difference For the Year Ending December 31, For the Year Ending December 31, For the Year Ending December 31, 2018E 2019E 2020E 2021E 2022E 2023E 2018A 2019E 2020E 2021E 2022E 2023E 2018E 2019E 2020E 2021E 2022E 2023E A Natural Gas Gathering and Processing $27.7 $46.9 $62.6 $69.4 $71.1 $71.6 $24.5 $38.6 $59.7 $68.6 $71.8 $73.1 ($3.2) ($8.3) ($2.9) ($0.8) $0.7 $1.5 B Natural Gas Transportation 27.5 20.2 21.1 21.5 22.3 22.3 27.9 22.3 23.5 25.2 26.0 26.0 0.4 2.1 2.3 3.7 3.7 3.7 C Offshore Pipelines 80.1 71.7 70.5 63.8 57.3 49.8 79.6 75.5 74.5 66.1 60.9 53.9 (0.5) 3.9 4.0 2.4 3.6 4.1 D Distributions from Delta House 40.3 94.2 59.1 47.5 44.0 34.2 40.2 86.7 63.5 47.7 44.3 34.4 (0.1) (7.5) 4.4 0.3 0.3 0.2 nt E Trucking (1.5) 0.3 (0.8) (0.1) (0.1) (0.1) (1.9) (1.1) (1.0) (1.0) (1.0) (1.0) (0.4) (1.4) (0.3) (0.9) (0.9) (0.9) e gm F Bakken Crude Oil Gathering 2.3 2.8 3.7 3.2 2.2 1.3 1.3 3.6 4.4 3.8 2.9 2.1 (0.9) 0.8 0.6 0.7 0.7 0.7 e S G Silver Dollar Pipeline 14.5 8.6 13.9 15.8 15.6 16.0 16.1 10.0 19.3 22.0 22.1 22.7 1.6 1.3 5.4 6.2 6.4 6.7 by H Terminals 24.0 (1.1) 4.5 4.5 4.5 4.5 25.1 (1.1) 4.5 4.5 4.5 4.5 1.1 (0.0) (0.0) (0.0) (0.0) (0.0) A I NGL Pipeline JV Distributions 11.5 15.4 15.7 15.5 14.4 13.4 11.1 15.2 15.7 15.5 14.4 13.4 (0.4) (0.1) (0.0) (0.0) (0.0) (0.0) I TD EBITDA $226.4 $259.0 $250.4 $240.9 $231.3 $213.0 $223.8 $249.8 $264.0 $252.4 $245.8 $229.1 ($2.6) ($9.3) $13.6 $11.5 $14.5 $16.0 E B J Corporate G&A ($57.7) ($46.7) ($46.7) ($46.7) ($46.7) ($46.7) ($56.4) ($55.0) ($49.8) ($49.8) ($49.8) ($49.8) $1.3 ($8.2) ($3.1) ($3.1) ($3.1) ($3.1) D Delta House Distribution Support 17.7 -- -- -- -- -- 17.7 -- -- -- -- -- -- -- -- -- -- --J Other (1.2) -- -- -- -- -- (1.1) (0.1) (0.1) (0.1) (0.1) (0.1) 0.1 (0.1) (0.1) (0.1) (0.1) (0.1) Adjusted EBITDA $185.3 $212.4 $203.8 $194.3 $184.7 $166.4 $184.0 $194.7 $214.1 $202.5 $195.8 $179.1 ($1.2) ($17.7) $10.3 $8.2 $11.2 $12.7 A Natural Gas Gathering and Processing ($4.7) ($3.3) ($3.5) ($3.3) ($3.3) ($3.3) ($5.4) ($2.7) ($3.0) ($3.0) ($3.0) ($3.0) ($0.7) $0.6 $0.5 $0.3 $0.3 $0.3 nt B Natural Gas Transportation (1.1) (3.7) (3.5) (3.5) (3.5) (3.5) (1.2) (3.4) (3.5) (3.5) (3.5) (3.5) (0.1) 0.4 -- -- -- --l e pit a egm C Offshore Pipelines (1.0) (3.9) (4.0) (4.0) (4.0) (4.0) (1.9) (6.9) (4.0) (4.0) (4.0) (4.0) (0.9) (3.0) -- -- -- --a S E Trucking -- (0.3) -- -- -- -- -- -- -- -- -- -- -- 0.3 -- -- -- -- C by F Bakken Crude Oil Gathering (0.0) -- (0.1) (0.1) (0.1) (0.1) (0.1) (0.1) (0.1) (0.1) (0.1) (0.1) (0.1) (0.1) 0.0 0.0 0.0 0.0 nditures nance G Silver Dollar Pipeline -- (0.8) (0.6) (0.5) (0.4) (0.4) -- (0.4) (0.5) (0.5) (0.4) (0.4) -- 0.4 0.0 0.0 0.0 0.0 int e H Terminals (1.0) (3.8) -- -- -- (0.9) (3.4) (3.8) -- -- -- -- (2.4) 0.0 -- -- -- 0.9 Ma pe I NGL Pipeline JV Distributions -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- --Ex J Corporate / Other (0.8) (2.6) (0.2) (0.2) (0.6) (0.6) (0.8) (2.6) (0.2) (0.1) (0.5) (0.6) -- (0.0) -- 0.1 0.0 0.0 Maintenance Capital Expenditures ($8.6) ($18.5) ($11.8) ($11.6) ($11.8) ($12.7) ($12.8) ($19.9) ($11.3) ($11.2) ($11.5) ($11.5) ($4.2) ($1.5) $0.5 $0.4 $0.3 $1.2 A Natural Gas Gathering and Processing ($21.7) ($93.0) ($41.6) ($22.1) ($18.7) ($18.7) ($29.7) ($104.1) ($55.0) ($29.4) ($26.1) ($25.1) ($8.0) ($11.1) ($13.4) ($7.4) ($7.4) ($6.4) itures B Natural Gas Transportation (6.4) (7.8) (1.1) (0.9) -- -- (3.7) (8.4) (1.1) (0.9) -- -- 2.7 (0.6) 0.0 (0.0) -- --nd C Offshore Pipelines (24.6) -- -- -- -- -- (22.8) (4.3) -- -- -- -- 1.8 (4.3) -- -- -- --Expe ent E Trucking (0.0) (0.1) (0.1) (0.1) (0.1) (0.1) -- -- -- -- -- -- 0.0 0.1 0.1 0.1 0.1 0.1 F Bakken Crude Oil Gathering (0.9) -- -- -- -- -- (1.1) -- -- -- -- -- (0.2) -- -- -- -- --l gm ta Se G Silver Dollar Pipeline (15.2) (6.2) (0.6) -- -- -- (14.1) (14.3) (12.6) -- -- -- 1.1 (8.1) (12.0) -- -- --pi Ca by H Terminals (4.2) -- -- -- -- -- -- -- -- -- -- -- 4.2 -- -- -- -- --owth I NGL Pipeline JV Distributions -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- --J Corporate (3.5) -- -- -- -- -- (3.5) -- -- -- -- -- -- -- -- -- -- -- G r Growth Capital Expenditures ($76.6) ($107.2) ($43.3) ($23.1) ($18.8) ($18.8) ($74.9) ($131.1) ($68.6) ($30.4) ($26.1) ($25.1) $1.6 ($23.9) ($25.3) ($7.3) ($7.3) ($6.3) Source: AMID Management 4

Preliminary Draft Subject to Change Executive Summary Material Changes Since February 5 Meeting Change to Change to 2019E EBITDA Primary Drivers 2023E EBITDA Primary Drivers Updated commodity price curve to February Updated commodity price curve to February 15, 2019 ($3.1 million) 15, 2019 ($1.7 million) Delayed acquisition of Pascagoula Gas Plant Updated fees for Longview ($1.3 million) from January 1, 2019 to April 1, 2019 ($4.2 Reallocated intercompany expenses with million) liquids trucking ($1.6 million) Natural Gas Reallocated intercompany expenses with Updated volumes for Chatom Bazor Ridge Gathering and ($8.3 million) liquids trucking ($1.6 million) $1.5 million and Yellow Rose ($1.2 million) Processing Reduced Chatom Bazor Ridge Volumes ($2.2 million) Decrease in Pascagoula Gas Plant EBITDA ($2.0 million) Removed direct allocation of G&A expenses Updated Lavaca drilling pace to 3 rigs from ($3.2 million) 2019E – 2023E ($6.7 million) Removed direct allocation of G&A expenses ($3.2 million) Removed direct allocation of G&A expenses Removed direct allocation of G&A expenses Natural Gas $2.1 million $3.7 million ($2.6 million) ($2.6 million) Transportation Updated Rate Case at AlaTenn ($0.9 million) Updated Volumes ($3.5 million) Updated Volumes ($2.7 million) Updated High Point Rate to $0.12 / Dth net to Updated High Point Rate to $0.12 / Dth net to Offshore $3.9 million AMID from $0.04 / Dth net to AMID ($2.6 million) $4.1 million AMID from $0.04 / Dth net to AMID ($2.1 million) Removed direct allocation of G&A expenses Removed direct allocation of G&A expenses ($4.5 million) ($4.5 million) Delta House ($7.5 million) Updated 2019E volumes for downtime and $0.2 million Updated Delta House corporate expense turnaround ($7.5 million) $0.2 million Updated volumes and rates ($2.6 million) Updated volumes and rates ($1.2 million) Updated for Earthstone buildout ($2.1 million) Updated for Earthstone project ($4.7 million) Silver Dollar $1.3 million Removed direct allocation of G&A expenses $6.7 million Removed direct allocation of G&A expenses ($0.8 million) ($0.8 million) Updated corporate expenses for new budget Adjusted for public company G&A savings ($9.3 ($8.2 million) ($2.1 million) ($3.1 million) million, $5.0 million incremental to 2019E) Corporate Adjusted for public company G&A savings ($4.3 Added back direct allocation of G&A expenses G&A million) ($12.2 million)1 Added back direct allocation of G&A expenses ($12.2 million)1 Source: AMID Management 1. Includes $0.5 million allocated to Bakken Crude Oil Gathering and other adjustments to G&A expenses 5 Preliminary Draft Subject to Change Executive Summary Detail of Changes Since February 5 Meeting All projections were updated to reflect December 2018A results and February 15, 2019 strip pricing (Impact to 2019E EBITDA $3.1 million lower; 2023 EBITDA: $1.7 million lower) Additional changes to the projections, detailed by segment, are included below: A Natural Gas Gathering & Processing: (i) updated producer rig assumptions (material adjustments included increasing Penn Virginia Corporation’s (“PVAC”) rigs on the Lavaca system from two to three from 2019E to 2023E, (ii) delayed acquisition of Pascagoula gas plant for $36.3 million until April 1, 2019 (iii) adjusted compressor program capital expenditures, (iv) adjusted the growth capital expenditure projections for the Longview expansion given purity ethane customer request (increase of $13 million), (v) updated the Longview contract and frac fees, (vi) removed all direct allocations of corporate G&A to natural gas G&P segment and (vii) updated operating expenses including those associated with NGL trucking volume adjusted for new rig assumptions B Natural Gas Transportation: (i) adjusted MLGT for updated contracts and the Enervest contract settlement, (ii) added Magnolia Spotlight contract, (iii) increased BP FT volumes, (iv) eliminated all direct allocation of corporate G&A to natural gas transportation segment and (v) updated operating expenses C Offshore Pipelines: (i) updated historical and projected volumes (ii) increased High Point volume rate $0.12 / Dth net to AMID from $0.04 / Dth net to AMID, (iii) eliminated all direct allocation of corporate G&A to natural gas transportation AMID segment and (iv) updated operating expenses Financial D Delta House: (i) updated January volume estimates, (ii) adjusted for January and February 2019 downtime, (iii) added Projections Delta House budgeted corporate expenses, (iv) adjusted for January 2019 volumes, and (v) updated operating expenses E Trucking: (i) Closed Texas Panhandle trucking operations on January 31, 2019 and reallocated assets to West Texas (Silver Dollar) and South Texas, (ii) updated South Texas volumes, (iii) updated operating expenses and (iv) eliminated all direct allocation of corporate G&A to trucking segment F Bakken Crude Oil Gathering: (i) eliminated all direct allocation of corporate G&A to liquids segment G Silver Dollar Pipeline: (i) updated producer rig assumptions including increasing Hunt rigs from 0.1 -0.2 to 0.5 in 2021E – 2023E, (ii) incorporated the Earthstone build-out, (iii) updated operating expenses to remove all direct corporate allocations and updated other miscellaneous expenses, (iv) updated forecasted rates and margins for Discovery, Approach, Henry, PT, Hunt, EP, the volume wedge and storage, (v) increased projected storage margins, (vi) moved capital recovery end-date from March 2019 to 2018 and (vii) shifted certain Texas Panhandle trucking assets to West Texas operations H Terminals: No material changes to financial projections I NGL Pipeline JV Distributions: No material changes to financial projections J Corporate G&A / Other: (i) Added back the previously allocated SG&A from segments and (ii) updated insurance expense Source: AMID Management 6

Preliminary Draft Subject to Change Executive Summary Detail of Changes Since February 5 Meeting (cont’d) Given AMID equity market capitalization decline resulting in higher market risk premium / higher weighted average cost of capital (“WACC”), Evercore adjusted its WACC methodology to utilize a size premium based on the implied equity market capitalization for each segment derived by multiplying the peer median equity market capitalization percentage of total capital to each segment’s estimated enterprise value This resulted in a lower WACC / higher resulting valuation in certain circumstances Evercore adjusted its WACC and trading multiple ranges as a result of changes in market data impacting the Discounted Cash Flow Analysis, Precedent M&A Transaction Analysis and Peer Group Trading Analysis as follows: AMID Total Partnership: increased WACC to 9.5% – 10.5% from 9.0 – 10.0% and EV / EBITDA multiple to 8.5x – 10.5x from 8.0x – 10.0x in the 2019E Peer Group Trading Analysis Natural Gas Gathering & Processing: decreased WACC range to 7.5% – 8.5% from 8.0% – 9.0% in the Discounted Cash Flow Analysis, decreased discount rate to 8.0% from 8.5% in the Precedent M&A Transaction Analysis and increased EV / EBITDA Evercore’s multiple to 9.0x – 11.0x from 8.5x – 9.5x in the 2019E Peer Group Trading Analysis Analysis of Natural Gas Transportation: increased WACC range to 10.0% – 11.0% from 7.5% – 8.5% in the Discounted Cash Flow the Analysis, increased discount rate to 10.5% from 8.0% in the Precedent M&A Transaction Analysis and increased EV / EBITDA multiple to 9.0x – 11.0x from 8.0x – 10.0x in the 2020E Peer Group Trading Analysis Proposed Offshore Pipelines: increased EV / EBITDA multiple to 7.5x – 10.0x from 7.5x – 9.5x in the 2020E Peer Group Trading Transaction Analysis Bakken Crude Gathering: increased WACC range to 12.0% – 13.0% from 7.5% – 8.5% and EBITDA exit multiple from 6.0x –8.0x to 7.0x – 9.0x in the Discounted Cash Flow Analysis and increased discount rate to 12.5% from 8.0% in the Precedent M&A Transaction Analysis Silver Dollar: increased WACC range to 9.5% – 10.5% from 7.5% – 8.5% in the Discounted Cash Flow Analysis and increased discount rate to 10.0% from 8.0% in the Precedent M&A Transaction Analysis Cushing Terminal: increased WACC range to 10.0% – 11.0% from 7.0% – 8.0% in the Discounted Cash Flow Analysis, increased discount rate to 10.5% from 7.5% in the Precedent M&A Transaction Analysis and decreased EV / EBITDA multiple to 7.0x – 8.0x from 7.5x – 9.0x in the 2020E Peer Group Trading Analysis, which is also utilized in the 2019E Peer Group Trading Analysis NGL JV Interests: increased EV / EBITDA multiple to 11.0x – 13.0x from 10.5x – 12.5x in the 2019E Peer Group Trading Analysis and increased EV / EBITDA multiple to 9.5x – 11.5x from 9.0x – 11.0x in the 2020E Peer Group Trading Analysis Divestitures planned by AMID management (excluded from the AMID Financial Projections) adjusted as follows: Lavaca added to list of planned divestitures at an estimated value of $120.0 million assumed to be sold on September 30, 2019 Natural Gas Transportation estimated divestiture value decreased to $200.0 million from $207.0 million from the February 5 Other Meeting Bakken Crude Gathering estimated divestiture value decreased to $30.0 million from $40.0 million from the February 5 Meeting Silver Dollar estimated divestiture value decreased to $125.0 million from $150.0 million from the February 5 Meeting Cushing Terminal added to list of planned divestitures at an estimated value of $30.0 million assumed to be sold on December 31, 2019 Source: AMID Management 7 Preliminary Draft Subject to Change Executive Summary Current Summary AMID Partnership Structure As-Converted % of % of Entity Common Units LP Units Total Units ArcLight Energy Partners Fund V, LP ArcLight Energy Partners Fund V, LP 2,853,482 3.6% 3.6% Magnolia Infrastructure Holdings, LLC 21,383,461 27.3% 27.0% 2,853,482 Common Units1 Magnolia Infrastructure Partners, LLC 4,977,063 6.4% 6.3% High Point Infrastructure Partners, LLC 10,172,347 13.0% 12.8% Magnolia Infrastructure Holdings, LLC American Midstream GP, LLC 1,349,609 1.7% 1.7% ArcLight and Affiliate-Owned LP Units 40,735,962 52.0% 51.3% 10,563,942 Common Units American Midstream GP, LLC (GP Units) 980,889 1.2% 9,514,330 Series C Units representing 9,527,650 Common Units ArcLight and Affiliate-Owned Units 41,716,851 52.6% 1,291,869 Common Units issuable upon exercise of warrant2 93.0% Magnolia Infrastructure Partners, LLC Public 618,921 Common Units 3,401,875 Series A-2 Units representing 4,358,142 Common Units AMID GP Holdings, LLC Unitholders 37,619,673 High Point Infrastructure Partners, LLC3 Common Units 7,940,322 Series A-1 Units representing 10,172,347 Common Units 48.0% LP Interest 77.0% 23.0% American Midstream GP, LLC 1,349,609 Common Units 1.2% GP Interest, 1.7% LP Interest and 100% of IDRs 13.0% LP Interest American Midstream Partners, LP (“AMID”) 6.4% LP Interest Market Capitalization: $207.3 MM4 Preferred Equity: $324.6 MM5 Net Debt as of 12/31/2018: $1,014.6 MM5 27.3% LP Interest 100% Ownership American Midstream, LLC 100% Ownership 3.6% LP Interest Direct and Indirect Wholly- Source: Public filings, AMID management Owned Subsidiaries Note: Units outstanding provided by AMID management on January 9, 2019 1. Common units owned by Busbar II, LLC, a wholly-owned direct subsidiary of ArcLight Energy Partners Fund V, LP 2. Warrant issued to Magnolia Holdings by AMID dated April 25, 2016 3. High Point Infrastructure Partners, LLC is a portfolio company of ArcLight Capital Partners, LLC 4. Pricing as of March 7, 2019 5. Book value based on Preliminary December 31, 2018 balance sheet as provided by AMID management 8

Preliminary Draft Subject to Change Executive Summary Merger Analysis ($ in millions, except per unit amounts) Proposed Consideration $5.25 LP Units Outstanding1 (MM) 54.0 AMID LP Equity Value $283.4 Plus: AMID Net Debt 1,132.4 Plus: Liquidation Value of Series A-1 Convertible Preferred Units 2 147.5 Plus: Liquidation Value of Series A-2 Convertible Preferred Units 3 63.2 Plus: Liquidation Value of Series C Convertible Preferred Units 4 141.8 Plus: Noncontrolling Interest 13.8 Transaction Value $1,782.2 Premium Metric Unit Price as of September 27, 2018 (Unaffected Price prior to Initial Proposal) $5.75 (9%) 10-Day VWAP 5.99 (12%) 30-Day VWAP 6.28 (16%) 60-Day VWAP 6.91 (24%) Unit Price as of January 3, 2019 (Unaffected Price prior to Second Proposal) 3.15 67% 10-Day VWAP 3.85 36% 30-Day VWAP 4.31 22% 60-Day VWAP 5.01 5% Unit Price as of March 7, 2019 3.84 37% 10-Day VWAP 3.96 33% 30-Day VWAP 4.02 31% 60-Day VWAP 4.02 31% Transaction Value / 2018A EBITDA5 $159.1 11.2x (Transaction Value + 2019E Growth Capital Expenditures + Acquisitions) / 2019E EBITDA5 194.7 10.5 Price / DCF per LP Unit 2018A5 $0.70 7.5x 2019E 1.21 4.4 Source: AMID management, public filings, Bloomberg 1. Includes 980,889 general partner units 2. 7,707,571 Series A-1 convertible preferred units multiplied by the liquidation value of $18.52 per unit (adjusted for accrued 1Q19 and 2Q19 distributions and accrued interest on 1Q19 distribution) 3. 3,302,158 Series A-2 convertible preferred units multiplied by the liquidation value of $18.52 per unit (adjusted for accrued 1Q19 and 2Q19 distributions and accrued interest on 1Q19 distribution) 4. 9,241,642 Series C convertible preferred units multiplied by the liquidation value of $14.87 per unit (adjusted for accrued 1Q19 and 2Q19 distributions and accrued interest on 1Q19 distribution) 5. Pro forma for sale of refined product terminals to Sunoco LP 9 Preliminary Draft Subject to Change II. Situation Analysis

Preliminary Draft Subject to Change Situation Analysis Summary Market Data ($ in millions, except per unit amounts) Market Capitalization Balance Sheet and Credit Data As of December 31, 2018 As of March 7, 2019 Cash and Marketable Securities $9.1 Total Units Outstanding1 54.0 Short-Term Debt 523.0 Common Unit Price $3.84 Long-Term Debt 500.7 Total Equity Value $207.3 Total Debt $1,023.7 Plus: Preferred Equity2 324.6 Net Debt $1,014.6 Plus: Net Debt 1,014.6 Plus: Noncontrolling Interest 13.8 Plus: Noncontrolling Interest 13.8 2 Plus: Preferred Equity 324.6 Enterprise Value $1,560.3 Plus: Partners’ Capital 105.5 FactSet Consensus AMID Financial Projections Net Book Capitalization $1,458.5 Metric Yield/Multiple Metric Yield/Multiple Revolver Availability / Total Revolver Capacity $66.1 / $620.0 Distribution Yield Net Debt / Net Book Cap 69.6% Current $-- --% $-- --% Net Debt / 2018A EBITDA 6.4x 2019E -- --% -- --% Net Debt / 2019E EBITDA 5.2 2020E -- --% -- --% EV/EBITDA Current Ratings (Senior Unsecured): 2018 $186.2 8.4x $159.1 9.8x Moody’s Caa2 2019E 180.6 8.6 194.7 8.0 S&P B 2020E 189.7 8.2 214.1 7.3 Unit Price Performance General Partner Incentive Distribution Rights Quarterly Total Total Total Total $20.00 $2.50 D LP Quarterly Quarterly Distribution Total Quarterly Quarterly Annual Annual i Distribution Distribution to GP LP Units Distribution Distribution Distribution Distribution $2.00 s tri % to LP % to GP Range Within Range per LP Unit Outstanding to LPs to GP to LPs to GP $15.00 b 98.7% 1.3% $-- $0.4125 $-- $-- 53.0 $-- $-- $-- $--50.7% 49.3% 0.4125 0.4125 -- -- 53.0 -- -- -- -- ice ution $1.50 50.7% 49.3% 0.4125 0.4125 -- -- 53.0 -- -- -- --r P 50.7% 49.3% 0.4125 -- -- 53.0 -- -- -- -- $10.00 $-- $-- $-- $-- Unit $1.00 $3.84 p $5.00 er % of Total Distributions to the GP NM $0.50 Unit % of Total Distributions to the IDRs NM $-- $--3/7/17 7/31/17 12/24/17 5/19/18 10/12/18 3/7/19 Distribution per Unit Unit Price Source: Company filings, AMID management and FactSet Note: Market data as of March 7, 2019 1. Includes 980,889 general partner units 2. Book value of preferred based on Preliminary December 31, 2018 balance sheet as provided by AMID management 10 Preliminary Draft Subject to Change Situation Analysis Summary Market Data (cont’d) AMID 8.5% Senior Notes due 2021 Trading Price / AMID Unit Price Yield to Worst $18.00 105.00 14.0% 104.00 13.1% $16.00 103.00 12.0% 102.00 $14.00 101.00 10.0% $12.00 100.00 st 99.00 $10.00 8.0% 98.00 o Wor Price 97.00 $8.00 96.00 6.0% eld t I $6.00 95.00 Y $3.84 94.00 4.0% $4.00 93.00 92.00 2.0% $2.00 91.00 91.88 $-- 90.00 0.0% 3/7/18 5/19/18 7/31/18 10/12/18 12/24/18 3/7/19 3/7/2018 5/6/2018 7/6/2018 9/5/2018 11/5/2018 1/5/2019 3/7/2019 Price Yield to Worst AMID Revolving Credit Facility Cost of Borrowing1 Covenant Consolidated Total Leverage Ratio2 Maximum Consolidated total leverage per AMID credit agreement decreases from 6.5x 6.25x currently to 5.75x for the quarter 7.00% 6.1x ending June 30, 2019 5.8x 6.1x 5.9x 5.8x 5.8x 5.5x 6.59% 5.1x 6.50% 4.8x 4.9x 4.7x 4.7x 6.00% 4.1x 3.7x 3.5x 3.4x 3.4x 5.50% 5.00% 4.50% 4Q ‘18 1Q ‘19 2Q ‘19 3Q ‘19 4Q ‘19 1Q ‘20 2Q ‘20 3Q ‘20 4Q ‘20 4.00% 3/7/2018 5/6/2018 7/6/2018 9/5/2018 11/5/2018 1/5/2019 3/7/2019 AMID AMID Financial Financial Projections Projections – No Divestitures Max Consolidated Total Leverage Ratio Source: Bloomberg, FactSet, AMID management 1. Assumes 3-month LIBOR plus 4.00% 2. Total consolidated leverage ratio per Second Amendment to Second Amended and Restated Credit Agreement excludes non-recourse debt related to natural gas transportation as well as the convertible preferred units 11

Preliminary Draft Subject to Change Situation Analysis Wall Street Research Summary Broker Research Summary: UBS (January 8, 2019) Neutral Rating (maintained from November 19, 2018) Price Target: $4.00 / unit (reduced from $6.00 / unit as of November 19, 2018) 2019E EBITDA: $180.6 million (reduced from $196.3 million as of November 19, 2018) Summary of AMID Broker Coverage 8 $20.00 6 $16.00 1 1 s Uni ing $12.00 t Ra 1 1 t 4 2 Price 1 oker $8.00 r 2 B 1 $4.00 2 4 2 $4.00 $3.84 3 3 2 2 1 1 1 1 0 $0.00 Feb-17 May-17 Aug-17 Nov-17 Feb-18 May-18 Aug-18 Nov-18 Feb-19 Buy Hold Sell Price NTM Target Price Source: FactSet, Wall Street research, Bloomberg 12 Preliminary Draft Subject to Change Situation Analysis Historical Trading Performance $20.00 4,000 $16.00 3,000 AMID A C D E G H I B F $12.00 L Trading Price K J 2,000 i t n Volu U $8.00 m e M N O AMID $4.00 1,000 (000’s P Q ) $-- --3/7/17 5/19/17 7/31/17 10/12/17 12/24/17 3/7/18 5/19/18 7/31/18 10/12/18 12/24/18 3/7/19 A 3/20/17: Upsized credit facility from $750 million to $900 million K 6/29/18: Amended credit facility agreement to reduce borrowing B 6/2/17: Acquired Vioska Knoll gathering system for $32 million capacity by $200 million to $700 million upon consummation of C 7/24/17: Entered definitive agreement to sell propane business to the sale of marine products terminals. Six of 19 lending banks SHV Energy N.V. for $170 million in cash asked for AMID to halt common unit and preferred distributions D 8/8/17: Announced the acquisition of Panther assets for $52 million L 7/27/18: Announced distribution reduction to $0.1031 per LP unit and entry into a JV agreement with Targa Midstream Services per quarter from $0.412, a 75.5% decrease creating Cayenne Pipeline, LLC M 7/29/18: Southcross provides notice of termination of the E 10/2/17: Acquired an additional 15.5% equity interest in Delta House Contribution Agreement from ArcLight for $125 million N 9/28/18: Announced receipt of an unsolicited non-binding F 10/30/17: Acquired an additional 17.0% interest in the Destin Pipeline proposal from ArcLight, pursuant to which ArcLight would acquire from ArcLight for $30 million all unaffiliated common units of AMID in exchange for $6.10 per G 11/1/17: Announced acquisition of certain assets of Southcross common unit in cash Holdings, LP and proposed to merge with Southcross Energy O 11/15/18: Entered into a definitive agreement to sell its refined Partners, LP (“Southcross”) in transactions valued at $815 million products terminal business to Sunoco, LP for $125 million H 11/6/17: Announced the acquisition of the equity interests in Trans- P 12/31/18: Amended credit agreement and announced elimination Union Interstate Pipeline from ArcLight for $48 million of distributions to common units and preferred units I 12/14/17: Priced $125 million 8.5% Senior Notes due 2021 Q 1/3/19: Announced receipt of the Second Proposal from ArcLight, J 6/18/18: Entered into a definitive agreement to sell its marine pursuant to which ArcLight would acquire all unaffiliated common products terminals to institutional investors for $210 million units of AMID in exchange for $4.50 per common unit in cash Source: FactSet, S&P Capital IQ, filings, AMID management Note: Market data as of March 7, 2019 13

Preliminary Draft Subject to Change Situation Analysis Equity Ownership Summary – Excludes 1,291,869 Common Units Related to Warrants Summary Institutional Ownership Institution Units (000’s) Ownership % OppenheimerFunds Inc 6,319 8.1% Swank Capital LLC 2,379 3.0% Institutional/Other (Net of Prescott Group Capital Management 1,912 2.5% Short Interest), 22.7% Retail, 24.5% UBS AG 1,900 2.4% JPMorgan Chase & Co 911 1.2% MFP Investors LLC 775 1.0% Goldman Sachs Group Inc/The 593 0.8% Bank of America Corp 502 0.6% ClearBridge LLC 312 0.4% Creative Planning Inc 240 0.3% HITE Hedge Asset Management LLC 219 0.3% Cohen & Steers Inc 218 0.3% Neuberger Berman Group LLC 201 0.3% Morgan Stanley 200 0.3% ELCO Management Co LLC 168 0.2% Top 15 Institutional 16,851 21.6% Insiders, 52.8% Short Position2 701 0.9% Insider Ownership Unaffiliated Unitholders Holder Units (000’s) Ownership % Holder Units (000’s) Ownership % ArcLight Energy Partners Fund V, LP1 40,425 51.8% Institutional/Other (Net of Short Interest) 17,726 Management and Directors 751 1.0% Retail 19,142 Management and Directors 751 Total Insider 41,176 52.8% Total Unaffiliated Unitholders 37,620 48.2% Summary Holder Units (000’s) Ownership % Institutional/Other (Net of Short Interest) 17,726 22.7% Insiders 41,176 52.8% Retail 19,142 24.5% Total Units Outstanding 78,045 100.0% Source: Bloomberg, Public filings 1. Includes units held by ArcLight and its subsidiaries and affiliates, including 7,940,322 Series A-l Convertible Preferred Units (“Series A-1 Units”) held by High Point Infrastructure Partners, LLC (“High Point”), convertible into 10,172,347 Common Units, 3,401,875 Series A-2 Convertible Preferred Units held by Magnolia Infrastructure Partners, LLC (“Magnolia”), convertible into 4,358,142 Common Units, 9,514,330 Series C Convertible Preferred Units held by Magnolia Infrastructure Holdings, LLC (Magnolia Holdings), convertible into 9,527,650 Common Units, 10,563,942 Common Units held by Magnolia Holdings, 1,349,609 Common Units held by American Midstream GP, LLC, 618,921 Common Units held by Magnolia, 2,853,482 Common Units held by Busbar II, LLC and approximately 980,889 General Partner units; excludes Magnolia Holdings’ 1,291,869 common units related to warrants 2. Short interest per Wall Street Market Data as of February 15, 2019 14 Preliminary Draft Subject to Change Situation Analysis Review of AMID’s Acquisitions / Divestitures ($ in millions) Acquisitions Date Transaction EBITDA Announced Acquiror / Seller Description Value Multiple 11/6/17 American Midstream Partners, LP / ArcLight Capital Partners, LLC1 Trans-Union Interstate Pipeline, L.P. $48.0 6.5x 10/30/17 American Midstream Partners, LP / ArcLight Capital Partners, LLC1 17% interest in the Destin Pipeline 30.0 6.3 10/2/17 American Midstream Partners, LP / ArcLight Capital Partners, LLC1 15.5% interest in Delta House 125.4 7.1 8/8/17 American Midstream Partners, LP / ArcLight Capital Partners, LLC1 Remaining interests in MPOG and AmPan (Panther Operating) 52.0 7.0 6/2/17 American Midstream Partners, LP / Genesis Energy LP Vioska Knoll gathering system 32.0 7.0 11/1/16 American Midstream Partners, LP / ArcLight Capital Partners, LLC1 6.2% interest in Delta House 48.8 6.0 10/24/16 American Midstream Partners, LP / JP Energy Partners LP Crude oil pipelines; refined products terminals; NGL distribution 459.4 7.2 2 4/25/16 American Midstream Partners, LP / ArcLight Capital Partners, LLC1 GoM offshore pipeline assets 225.0 6.0 8/10/15 American Midstream Partners, LP / ArcLight Capital Partners, LLC1 12.9% interest in Delta House 162.0 5.0 10/14/14 American Midstream Partners, LP / Costar Midstream G&P assets in East Texas, Permian and Bakken 470.0 10.5 8/7/14 American Midstream Partners, LP / ArcLight Capital Partners, LLC1 Eagle Ford gas gathering system 110.0 --7/14/14 American Midstream Partners, LP / DCP Midstream LLC 67% interest in MPOG 13.5 5.5 1/22/14 American Midstream Partners, LP / Penn Virginia Corp. Eagle Ford gas gathering system 100.0 12.5 12/10/13 American Midstream Partners, LP / ArcLight Capital Partners, LLC1 Blackwater Midstream’s three multi-modal terminals 60.0 7.8 6/1/12 American Midstream Partners, LP / Quantum Resources Management, LLC 87.4% interest in Chatom Processing and Fractionation Plant 55.0 7.9 11/17/11 American Midstream Partners, LP / Marathon 50% interest in the Burns Point Gas Plant 38.0 -- Mean 7.3x Median 7.0 Divestitures Date Transaction EBITDA Announced Acquiror / Seller Description Value Multiple 11/15/18 Sunoco LP / American Midstream Partners, LP Caddo Mills and North Little Rock refined products terminals $125.0 7.3x 6/18/18 Institutional Investors / American Midstream Partners, LP Harvey and Westwego marine products terminals 210.0 13.9 7/24/17 SHV Energy N.V. / American Midstream Partners, LP Propane marketing and services business 170.0 9.0 Mean 10.1x Median 9.0 Source: AMID management, press releases, Partnership filings, 1Derrick, IHS 1. Also includes affiliates of ArcLight Capital Partners, LLC 2. Includes run-rate synergies 15

Preliminary Draft Subject to Change III. Asset Overview Preliminary Draft Subject to Change Asset Overview Overview of AMID’s Asset Base G&P Gas Transport Bakken Gathering Cushing Terminal NGL Pipelines Systems: 7 ~1.2 Bcfd FT and IT Miles: 47 Capacity: 3.0 MMBbl Pipeline Interests: 3 Miles: 1,300 volumes Capacity: 40 MBpd Tanks: 5 Ownership: 16.7%, 25.3% & 50.0% Processing Plants: 6 98% firm volumes Dedicated Acres: Capacity: 180 MBpd Processing Capacity: 6.7 years weighted 27,500 Miles: 254 157 MMcfd average contract term Dedicated Acres: 2019E Gross Margin Contribution 100,000 Bakken 4% 2% 1%1% Crude Delta House 5% Gathering and Processing Gathering Offshore Pipelines Excl. Delta House Legend Natural Gas Transportation 10% 27% Silver Dollar Pipeline G&P NGL JV Interest Bakken Crude Oil Gathering Gas Transportation Trucking Silver Dollar Cushing Terminal 25% 25% Bakken Gathering Offshore Pipelines Delta House NGL Pipelines Cushing Terminal Terminal Truckyard Offshore Pipelines Systems: 5 Natural Gas Permian G&P Transportation Miles: 1,318 Capacity: 8.5 Bcfed Silver Dollar Gulf Coast G&P E. Texas G&P Silver Dollar Crude Gathering Miles: 161 Trucking1 Offshore Delta House Capacity: 130 MBpd NGL Pipeline Pipelines Dedicated Acres: Trucks: 71 S. Texas G&P Interests Delta House 35.65% Interest 350,000 Truckyards: 5 Capacity: 100 MBpd of Truckyard: 1 crude oil and 240 MMcfd of natural gas Trucks: 22 1. Trucking segment includes only South Texas and Panhandle trucking assets; West Texas trucking assets grouped with Silver Dollar Pipeline 16

Preliminary Draft Subject to Change Asset Overview A Gathering & Processing –Permian (cont’d) ($ in millions, except per unit amounts) Yellow Rose System Utilization (MMcfd) Assumes 5-10 wells per year or a 0.5 to 1.0 rig rate 60.0 1.2 As of February 5Meeting 1.0 D 50.0 1 iam (MMcfd) 40 40.0 40.0 0.8 ondb 0.8 0.8 a Volume 30.0 0.5 0.5 0.6 ck Ri g 20.0 Permian 17.0 16.6 17.4 17.3 17.3 17.3 0.4 re Fo 13.2 12.7 7.3 7.3 7.7 7.7 8.0 8.9 10.0 6.0 6.0 6.6 6.8 0.2 cast 4.7 4.7 -- 0 2017A 1Q18A 2Q18A 3Q18A 4Q18A 2019E 2020E 2021E 2022E 2023E Yellow Rose Throughput (MMcfd) Yellow Rose Capacity (MMcfd) Diamondback Rig Forecast Asset EBITDA $9.0 $7.9 $8.0 $8.0 $6.5 $6.0 $4.0 $3.9 $3.9 $4.5 $3.9 $3.0 $3.8 $0.9 $0.7 $3.9 $4.1 $4.1 $0.3 $0.3 $0.0 $2.6 $0.1 $0.9 $0.1 $0.2 $0.5 $0.2 $0.6 $0.7 $-- ($0.3) ($0.6) ($0.0) ($3.0) 2017A 1Q18A 2Q18A 3Q18A 4Q18A 2019E 2020E 2021E 2022E 2023E Yellow Rose Mesquite1 Source: AMID management, public filings, Diamondback investor presentation 1. Mesquite EBITDA represents AMID earnings defined as 70% of gross margins less 50% of operating expenses 17 Preliminary Draft Subject to Change Asset Overview A Gathering & Processing – East Texas Asset Overview Asset Map Longview Gathering & Processing System The Longview Gathering and Processing System (“Longview”) in Gregg, Rusk and Smith Counties consists of 643 miles of high- and low-pressure gathering lines, two cryogenic processing plants with a design capacity of 50.0 MMcfd, one fractionation unit with 8,500 Bpd of capacity, a stabilization unit with 6,000 Bpd of off-spec condensate and NGL treating capacity, product storage tanks, NGL sales pipelines and a two-bay, semi-automated truck rack equipped to receive on- and off-spec NGLs and condensate Highly profitable legacy contracts providing for retention of a high percentage of liquids Currently providing economic incentives to spur workover activity Competes with Midcoast Operating L.P. (“Midcoast”) in the area In April 2016, AMID announced the commencement of operations at the East Texas Rail Facility, allowing for receipt and delivery of NGLs and condensate by rail to the Longview Processing Plant System Utilization (MMcfd) Includes more than 8,900 feet of lead track with current capacity for more than 50 general purpose or pressure railcars Includes volume gains from workovers and 1-2 wells per year 80.0 on Longview and 1 well per year on Chapel Hill Ability to receive and deliver up to 4,500 Bpd of NGLs, including purity products and condensate, with similar capabilities for rail-to-truck 70.0 60.0 transloading 43.1 42.3 43.6 42.7 43.0 43.5 44.0 44.4 42.1 40.6 43.1 42.3 43.6 42.7 43.0 43.5 44.0 44.4 Chapel Hill Gathering & Processing System 42.1 40.3 40.0 Located near Smith County, Texas, the Chapel Hill Gathering and Processing System (“Chapel Hill”) consists of 100 miles of gathering lines with 2,540 horsepower (“HP”) of compression, a 20.0 MMcfd cryogenic 20.0 processing plant, a 1,250 Bpd fractionation unit, 190,000 gallons of product storage capacity and truck racks to deliver propane, butane and natural --gasoline Gathers casinghead gas and wet gas production from the Paluxy, Petit and Throughput (MMcfd) Capacity (MMcfd) Cotton Valley formations As of February 5Meeting Source: AMID management, public filings, DrillingInfo (2/28/19) 18

Preliminary Draft Subject to Change Asset Overview A Gathering & Processing – Eagle Ford Asset Overview Asset Map PVAC Acreage The Lavaca System (“Lavaca”) consists of 203 miles of high- PVAC Rig pressure and low-pressure pipelines located in Gonzales and Lavaca System Lavaca Counties, Texas 218.0 MMcfd of gas gathering design capacity, 24,960 HP of leased compression and 3,215 HP of owned compression 70,000 dedicated acres; key customers include Penn Virginia Corporation (“PVAC”) and Devon Energy (“Devon”) In January 2014, AMID acquired 120 miles of the system from PVAC for $100.0 million at an implied 12.5x EV / EBITDA multiple PVAC entered into a fee-based gathering agreement covering a 70,000-acre dedication for 25 years System Utilization (MMcfd) In August 2014, AMID exercised its right-of-first-offer to 310.5 322.0 350.0 Assumes 55 wells connected 286.5 262.7 acquire the Gonzales County full-well-stream gathering annually (3-rig pace) 260.1 245.1 system from ArcLight 300.0 229.2 225.7 203.3 AMID entered into a fee-based agreement with Forest Oil 250.0 183.5 Corporation 200.0 218.0 173.9 128.2137.1135.1 On December 13, 2018, AMID’s sale process for Lavaca 118.7 137.1137.1 150.0 106.3 ended with no definitive bids being received 118.7 128.2 106.3 Oil price decline 100.0 Uncertainty regarding closing of Denbury Resources 50.0 Inc.’s (“Denbury” or “DNR”) announced acquisition of -- PVAC Throughput (MMcfd) Capacity (MMcfd) Source: AMID management, public filings, Wall Street research, DrillingInfo (2/28/19) As of February 5Meeting 19 Preliminary Draft Subject to Change Asset Overview A Gathering & Processing – Eagle Ford – PVAC Transaction The future of producer-driven volumes near AMID’s Eagle Ford positionis in flux as the outcome of Denbury’s announced acquisition of PVAC remains unclear Transaction Overview Post-Announcement Share Price Performance On October 28, 2018, Denbury announced it had entered a 120.0% definitive merger agreement to acquire PVAC in a transaction valued at approximately $1.7 billion 100.0% 89.3% The proposed consideration includes: 80.0% 79.7% 12.4 shares of Denbury per share of PVAC and cash of $25.86 per PVAC share, representing consideration of 68.9% 60.0% $79.80 per share based on the closing price of Denbury common stock on October 26, 2018 40.0% 38.2% PVAC’s assets include: 20.0% 84,700 net acres in Gonzales, Lavaca and DeWitt 10/28/18 11/18/18 12/10/18 1/1/19 1/22/19 2/13/19 3/7/19 Counties >450 net locations and a 10-year drilling inventory with DNR PVAC upside from Austin Chalk and Upper Eagle Ford Proposed Consideration1 S&P Oil & Gas E&P Index Described by Denbury as delivering “top tier operating Post-Announcement Merger Arbitrage Spread margins” 25.0% As of March 7, 2019, the merger arbitrage PVAC is operating three rigs in Lavaca County as of spread was -$7.26, or (13.5%) February 2019 and plans to drill 50 wells in 2019 20.0% Select PVAC shareholders are pressuring the acquisition 15.0% regarding the quality of Denbury’s existing asset base, 10.0% expected synergies with PVAC and Eagle Ford EOR 5.0% potential (which EOG is currently pilot testing in close --% proximity to PVAC’s acreage) (5.0%) Mangrove Partners Master Fund, Ltd. is seeking votes (10.0%) against the merger and owns 11.4% of PVAC’s outstanding shares (15.0%) (13.5%) (20.0%) Source: AMID management, public filings, Wall Street research 10/28/18 11/18/18 12/10/18 1/1/19 1/22/19 2/13/19 3/7/19 1. Reflects shift in value of proposed consideration over time relative to PVAC’s share price as of the transaction announcement date of October 28, 2018 20

Preliminary Draft Subject to Change Asset Overview A Gathering & Processing – Gulf Coast Asset Overview1 Asset Map Chatom Gathering & Processing System The Chatom System (“Chatom”) consists of a 29-mile gathering system with 3,456 HP of compression, a 25.0 MMcfd cryogenic processing plant, a 1,900 Bpd NGL fractionation unit and a 160 long-ton per day sulfur recovery unit located in Washington County, AL Chatom gathers natural gas from onshore crude oil and natural gas wells in the Norphlet and Smackover formations in Alabama and Mississippi and has a truck rack and the capability to receive and fractionate NGLs Bazor Ridge System Chatom System AMID acquired an 87.4% interest in Chatom in July 2012 for $51 Plant million in cash from Quantum Resources Management, LLC at an Active Rig estimated 7.3x EV / EBITDA multiple Tellus Permit Chatom is located approximately 15 miles from AMID’s Bazor Ridge System Utilization processing plant in Wayne County, Mississippi 50.0 Bazor Ridge Gathering & Processing System 47.0 40.0 Benefit from six expected new wells The Bazor Ridge System (“Bazor”), located in Jasper, Clarke, Wayne permitted by Tellus Operating Group, LLC and Greene Counties, Mississippi, includes: on Bazor Ridge 30.0 169 miles of gas gathering pipeline ranging in diameter from three 14.8 14.9 14.9 14.8 to eight inches and three compressor stations with a combined 20.0 14.9 10.8 11.3 10.9 10.1 12.8 14.0 13.9 13.7 13.4 9.1 11.3 1,069 HP 10.8 10.9 9.1 7.5 10.0 22.0 MMcfd sour natural gas treating and cryogenic processing plant with four inlets and one discharge compressor with -- approximately 5,218 of combined HP Since 2016, Bazor has been used as a central gathering and compression facility while processing has been re-routed to Chatom Throughput (MMcfd) Capacity (MMcfd) As of February 5Meeting Source: AMID management, public filings, DrillingInfo (2/28/19) 1. Burns Point Plant, a 165.0 MMcfd Plant jointly owned 50% by AMID and 50% by Enterprise Products Partners L.P. (“Enterprise”) has been shut down since December 2017 due to maintenance issues 21 Preliminary Draft Subject to Change Asset Overview B Natural Gas Transportation – Forecast Summary ($ in millions) Volume Forecast (Dth/d) 1,300,000 1,282,443 1,280,000 15,028 1,260,000 1,260,272 1,237,535 1,247,285 1,247,285 1,247,285 1,240,000 52,059 1,212,451 1,218,219 1,218,219 1,218,219 1,220,000 1,200,000 1,192,936 15,370 15,370 15,370 1,188,422 12,130 12,130 12,130 1,180,000 15,368 15,370 12,130 14,630 1,160,000 1,215,356 1,140,000 1,190,719 1,190,719 1,190,719 1,120,000 1,158,424 1,165,436 1,100,000 1,080,000 2018A 2019E 2020E 2021E 2022E 2023E Firm Reservation Interruptible Marketing As of February 5Meeting Gross Margin Forecast $40.0 $36.1 2018A to 2019E margin decline driven by interruptible volume and non-recurring marketing fuel gains in 2018A $32.8 $33.7 $33.7 $35.0 $31.1 $2.1 $2.1 $7.5 $29.8 $2.0 $1.4 $1.5 $1.5 $30.0 $2.8 $0.5 $0.5 $1.1 $2.2 $1.4 $0.5 $2.3 $0.5 $25.0 $1.8 $0.6 $20.0 $15.0 $25.9 $26.4 $28.9 $29.6 $29.6 $24.5 $10.0 $5.0 $-- 2018A 2019E 2020E 2021E 2022E 2023E Firm Reservation Interruptible Marketing Other1 Source: AMID management 1. Other revenue include imbalance revaluation, non-cash revenue recognition, management fee revenue, facility fees and other revenue 22

Preliminary Draft Subject to Change Asset Overview C Offshore Pipelines (excl. Delta House) – Destin / Okeanos Asset Overview Originating offshore in the GoM, the Destin Pipeline (“Destin”) is a FERC-regulated, 255-mile natural gas transport system with total capacity of 1.2 Bcfd operated by AMID Destin interconnects with four producing platforms and six producer-operated laterals Destin’s 120-mile 24- and 36-inch diameter offshore portion terminates at the Pascagoula Processing Plant and extends 135 Destin miles north in Mississippi with 30- to 36-inch pipeline and is the sole delivery point for merchant-quality gas from the plant Contracted volumes on Destin are based on life-of-field dedication, dedicated volumes over a given period, or interruptible volumes as capacity permits AMID owns a 66.7% interest in Destin, having acquired a 49.7% interest in 2016 (along with the Tri-States and Wilprise pipelines) for $225 million and an incremental 17% for $30 million in October 2017 Throughput driven by industrial, power and utility demand in Florida, Alabama and Mississippi In conjunction with its April 2016 acquisition of Destin, Tri-States and Wilprise, AMID purchased a 66.7% interest in the Okeanos system (“Okeanos”) from affiliates of ArcLight for $27.4 million in cash Okeanos 100 miles of 20- and 24-inch natural gas gathering pipeline that connects two producer platforms (Thunder Horse and Na Kika) and one lateral to the Destin Main Pass 260 platform (“MP260”) in the Mississippi Canyon region of the GoM 1.0 Bcfd of design capacity meeting capacity requirements for platforms currently connected and has existing capacity to accommodate third-party volumes via subsea tie-backs or new export lines Contracted volumes on Okeanos are based on life-of-field dedications from producers Enbridge, Inc. holds the minority interest in Okeanos Destin-Okeanos Throughput (MMBtud) 2,500 2,000 2,200 1,500 1,315 1,326 1,253 1,168 1,107 1,157 1,062 1,187 1,076 1,000 1,035 1,168 1,107 1,157 1,140 1,254 1,313 1,223 1,180 500 1,035 1,076 --2017A 1Q 2018A 2Q 2018A 3Q 2018A 4Q 2018A 2019E 2020E 2021E 2022E 2023E Throughput Capacity 2019E increase in volumes driven by spill-over As of February 5Meeting volumes from High Point Source: AMID management, public filings 23 Preliminary Draft Subject to Change Asset Overview C Offshore Pipelines (excl. Delta House) – High Point Asset Overview The 663-mile High Point system (“High Point”) with total pipeline capacity of 1,120 MMcfd consists of natural gas and liquids pipeline assets which gather natural gas from onshore and offshore areas in southeast Louisiana and the GoM Its onshore footprint is located in Plaquemines and St. Bernard Parish, Louisiana and its offshore footprint consists of the following GoM zones: Mississippi Canyon, Viosca Knoll, West Delta, Main Pass, South Pass and Breton Sound High Point gathers natural gas at more than 63 receipt points that connect to hundreds of wells targeting various geological zones in water depths up to 1,000 feet and delivers natural gas to the Toca Gas Processing Plant, operated by Enterprise, where it is processed and residue gas is sent to an unaffiliated interstate system owned by Kinder Morgan, Inc. High Point includes both FERC-regulated transmission assets (High Point Gas Transmission) and non-jurisdictional gathering assets (High Point Gas Gathering, Gloria, Lafitte and Chalmette Systems) High Point The Gloria Gathering System (“Gloria”) consists of approximately 138 miles of pipeline with diameters ranging from 3-to- 16 inches and four compressors with 2,962 HP AMID’s Lafitte System (“Lafitte”) consists of approximately 40 miles of gathering pipeline, with diameters ranging from 4-to-12 inches and a design capacity of 71 MMcfd Originating onshore, it terminates at the Alliance Refinery (owned by Phillips 66) in Plaquemines Parish, LA AMID is the sole supplier of natural gas to the Alliance Refinery pursuant to a contract that expires in 2026 The Chalmette System (“Chalmette”) is located in St. Bernard Parish and has a design capacity of 125 MMcfd High Point also includes Vioska Knoll Gathering System (“VKGS”), consisting of natural gas and crude oil gathering lines of varying diameters and the platform at VK817, purchased from Genesis Energy in 2017 for $32.0 million in cash High Point Throughput (MMBtud) 1,200 1,120 800 360 322 358 356 351 319 346 316 321 291 400 360 319 346 316 297 348 345 338 311 282 --2017A 1Q 2018A 2Q 2018A 3Q 2018A 4Q 2018A 2019E 2020E 2021E 2022E 2023E Throughput Capacity As of February 5Meeting Source: AMID management, public filings 24

Preliminary Draft Subject to Change Asset Overview C Offshore Pipelines (excl. Delta House) – MPOG and Panther Pipelines Asset Overview The Main Pass Oil Gathering System (“MPOG”) is a 100-mile crude oil gathering system located off the Southeast coast of Louisiana in the GoM Total design capacity of approximately 160,000 Bpd and currently operated by AMID’s wholly-owned subsidiary, Panther MPOG Operating Company, LLC Majority of volumes generated by life-of-lease contracts from a large, primarily investment-grade customer base In July 2014, AMID acquired a 67% interest in MPOG from an affiliate of DCP Midstream, LLC for approximately $13.5 million or approximately 5.0x to 6.0x NTM EBITDA In August 2017, AMID acquired Panther (including all outstanding equity interests in MPOG) for $52 million Located in Southern Louisiana and GoM, the American Panther system (“Panther Pipelines”) consists of approximately 200 Pipelines miles of crude oil, natural gas and salt water onshore and offshore GoM pipelines The system has a natural gas design capacity of 475 MMcfd and crude oil and saltwater capacity of 27.0 MBpd In August 2017, AMID acquired the Panther pipeline assets for approximately $60.9 million, including the Tiger Shoals / HGGS (AmPan), Quivira, Panther Operating Services and Matagorda systems Panther Originating offshore in Eugene Island Block 24 and terminating onshore in St. Mary Parish, LA, the Quivira Gathering System consists of 34 miles of pipeline Key customers include Cox Operating, LLC and Fieldwood Energy, LLC, with contract terms ranging from one year to 13 years MPOG and Panther Crude Oil Throughput (MBpd) Panther Pipeline Gas Throughput (MMBtud) 200 500 150 187 400 2019E volume increase due to new volumes 475 300 from Contango Oil and Gas Company 100 43 41 200 141 132 118 50 27 33 36 35 37 34 31 29 112 105 94 100 59 61 60 64 27 33 36 35 42 39 36 33 30 27 112 140 142 128 115 104 -- 59 61 60 64 2017A 1Q 2Q 3Q 4Q 2019E 2020E 2021E 2022E 2023E -- 2017A 1Q 2Q 3Q 4Q 2019E 2020E 2021E 2022E 2023E 2018A 2018A 2018A 2018A 2018A 2018A 2018A 2018A Throughput Capacity As of February 5Meeting Throughput Capacity As of February 5Meeting Source: AMID management, public filings 25 Preliminary Draft Subject to Change Asset Overview D Delta House Forecast ($ in millions) Volumes 120 350 Distributions increase in 2019E as debt 100.0 Debt Service Costs service costs cease as the term loan is 300 100 Na repaid in Q3 2018 89 89 88 88 t 240.0 77 85 81 81 77 77 250 ural (MBpd) t 80 75 75 p u Gas 63 63 200 gh u 60 56 56 ro h T 47 47 150 Throug h i l 38 38 pu O t Full capacity reached in 2019E as e 40 100 (M d ru M Capacity Reached anchor prospects connect BWOLF and cf C Red Zinger tie-in wells 20 50 ) d -- --2017A1Q18A2Q18A3Q18A4Q18A 2019E 2020E 2021E 2022E 2023E Crude Oil Volumes (MBpd) Natural Gas Volumes (MMcfd) Rates step down from $4.50 / Boe to Crude Oil Capacity (MBpd) Natural Gas Capacity (MMcfd) Crude Oil Volumes (MBpd) Natural Gas Volumes (MMcfd) Rate Step-Down $1.50 / Boe when cumulative As of February 5Meeting As of February 5Meeting production reaches 164.4 MBoe AMID’s 35.65% Interest in Total Revenue (projected February 2020) $120.0 $100.0 $89.3 $83.4 $8.0 $80.0 $8.0 Firm Transport Monthly fixed rate of $1.87 million $17.6 $16.4 $58.6 $56.7 expires in July 2022 $60.0 $49.8 $8.0 $8.0 $43.7 $0.3 $10.4 $8.0 $4.7 $35.1 $40.0 $18.5 $2.4 $27.6 $63.7 $18.7 $25.8 $59.1 $17.6 $1.7 $15.6 $2.9 $20.0 $40.3 $19.2 $12.2 2021E well connect assumed at a lower type $11.6 $23.0 $21.2 $17.1 $13.7 curve and rate of $1.50 / Boe $11.1 $11.3 $-- Tie-Backs 2017A 2018A 2019E 2020E 2021E 2022E 2023E 2024E 2025E 2022E well connect assumed at a higher type Anchor FPS – $4.50 / BOE Anchor FPS – $1.50 / BOE curve and rate of $1.50 / Boe Variable Gathering Rate Fixed Gathering Additional Tie-Back – $1.50 / BOE Source: AMID management 26

Preliminary Draft Subject to Change Asset Overview E Trucking (Texas Panhandle + South Texas) Asset Overview Asset Map AMID’s trucking assets (excluding the West Texas trucking assets categorized with the Silver Dollar Perryton, TX Pipeline) include five truckyards and 71 tractors located in South Texas and the Texas Panhandle Texas Panhandle tractors being re-deployed to South Texas and Silver Dollar in Q1 2019 Crude Truckyards Three truckyards located in Pearsall, Yoakum and Victoria in South Texas Marion, TX Yoakum, TX 20 operational trucks with one spare Legend Employees and contractors include 26 drivers, two Pearsall, TX Victoria, TX mechanics and one dispatcher Crude truckyard One truckyard located in Perryton, Texas in the Liquids truckyard Panhandle 20 operational trucks with one spare Volumes (MBpd) Employees and contractors include 27 drivers, two mechanics and one dispatcher As of February 5Meeting Decline in 2019E Note: Texas Panhandle operations closing in Q1 23.5 from shutdown of 19.2 19.4 20.6 20.6 20.6 20.6 2019 and trucks being redeployed in South Texas Texas Panhandle 14.7 16.4 16.4 16.4 16.4 operations and 16.0 and to Silver Dollar 14.7 2.6 redeployment of 2.4 2.4 2.4 2.4 2.4 Liquids Truckyard assets to South 2.1 0.8 Texas and 9.4 One truckyard in Marion, Texas in South Texas Permian 6.4 28 operational trucks with one spare 12.8 14.0 14.0 14.0 14.0 Employees and contractors include 28 drivers, two 6.2 7.2 mechanics and one dispatcher 2017A 2018A 2019E 2020E 2021E 2022E 2023E South Texas Crude Texas Panhandle Crude Liquids Trucking Source: AMID management, public filings 27 Preliminary Draft Subject to Change Asset Overview F Bakken Crude Gathering & Marketing Asset Overview Asset Map Located in McKenzie and Williams Counties in the Williston Basin, AMID’s FERC-regulated Bakken crude oil gathering system (“Bakken”) consists of: 47 miles of 10”, 8”, 6” and 4” pipeline with 40,000 Bpd of capacity Commenced operations in October 2015 Truck facility used to receive volumes has 10,000 Bpd of capacity and began operating in November 2015 LACT design with 81 current receipt points System holds a 10-year, fee-based, 27,500 acre dedication from Newfield (recently acquired by Encana) Sour crude treating (resuming in Q3 2019) Pipeline interconnects include: Andeavor’s High Plains Pipeline with 15 MBpd contractual and 24 MBpd theoretical capacity Dakota Access Pipeline’s 28.8 MBpd contractual capacity Volume (MBpd) As of February 5Meeting Legend 16.3 12.5 16.3 14.9 14.9 AMID System 12.5 12.5 12.5 10.4 Encana 9.2 8.8 6.8 6.2 10.4 DAPL Pipeline 7.3 4.0 5.2 7.3 4.3 Andeavor Pipeline 3.5 2.9 8.5 9.5 8.7 DAPL Interconnect 5.6 7.3 6.1 4.4 Andeavor Interconnect Trucking Facility 2017A 2018A 2019E 2020E 2021E 2022E 2023E Gathered Trucked Source: AMID management, public filings 28

Preliminary Draft Subject to Change Asset Overview G Silver Dollar (including West Texas Trucking and Marketing) (cont’d) Volumes (MBpd) 120.0 As of February 5Meeting 99.1 95.7 100.0 90.8 82.4 21.2 21.2 80.0 21.2 21.2 68.2 56.1 65.7 60.0 62.1 57.6 33.0 15.5 43.5 29.5 29.5 32.5 40.0 74.6 77.9 69.7 0.0 1.7 61.2 20.0 40.5 29.5 30.8 --2017A 2018A 2019E 2020E 2021E 2022E 2023E Gathered Trucking Well Connects by Producer 120.0 100.2 98.3 97.3 94.9 100.0 12.2 12.2 12.2 12.2 3.0 3.0 3.0 3.0 80.0 2.0 6.1 3.0 3.0 7.0 6.1 6.1 4.0 15.0 13.1 12.2 4.0 60.0 47.9 35.3 30.4 30.4 30.4 8.0 40.0 6.0 3.0 20.0 19.0 24.3 24.3 24.3 24.3 9.1 2.8 6.1 6.1 6.1 6.1 --2019E 2020E 2021E 2022E 2023E Approach EP Discovery Henry Hunt Earthstone Sequitur Other Source: AMID management, public filings 29 Preliminary Draft Subject to Change Asset Overview H Cushing Terminal (cont’d) Cushing Storage Overview Cushing Inventories versus Capacity The North American crude oil market is currently in 100,000 contango, which has led to growth in crude oil storage at Cushing and selling forward of growing quantities of 77,228 80,000 crude oil Inventories at Cushing were at an all-time high of 69,420 60,000 47,5231 MBbls on April 7, 2017 and declined to a three-year low MBbls 62% of Capacity of 21,803 MBbls on August 3, 2018 40,000 Cushing inventories have since rebounded marginally, 20,000 increasing weekly since August 3, 2018 - Crude oil inventory have increased for four Mar-11 May-12 Jul-13 Aug-14 Oct-15 Nov-16 Jan-18 Feb-19 consecutive weeks by approximately 4 MBbls per Capacity (MBbls) Crude Oil Stock (MBbls) week to 47,523 MBbls WTI Forward Price vs. Current ($56.66 2) Projected WTI Forward 12-Month Spread2 $2.50 $2.12 $2.00 $1.84 $1.50 $1.00 $1.29 $0.50 $-$0.82 $(0.50) $(1.00) $(1.50) $(2.00) 1-Month 3-Month 6-Month 12-Month Apr-19 Sep-19 Mar-20 Sep-20 Mar-21 Sep-21 Apr-22 Source: EIA, Bloomberg 1. As of March 1, 2019 2. As of March 7, 2019 30

Preliminary Draft Subject to Change Asset Overview I NGL Pipeline Interests (cont’d) Volumes (MBpd) 140.0 As of February 5Meeting 120.9 123.8 120.6 117.1 123.8 120.0 120.9 120.6 115.6 112.1 112.1 104.5 32.9 31.9 31.9 104.5 100.0 36.7 28.2 87.8 25.0 87.8 80.0 34.0 55.1 57.1 60.0 55.9 50.4 54.8 53.7 40.0 53.8 20.0 33.9 33.9 30.0 32.8 29.1 25.8 -- 2017A 2018A 2019E 2020E 2021E 2022E 2023E Cayenne (50.0% Ownership) Tri States (16.7% Ownership) Wilprise (25.0% Ownership) Source: AMID management, public filings 31 Preliminary Draft Subject to Change IV. AMID Financial Projections

Preliminary Draft Subject to Change AMID Financial Projections AMID Financial Projections – Assumptions The AMID Financial Projections utilized herein by Evercore incorporate the following AMID management assumptions: 2018A actuals Revenue / Expenses: 2018A –2023E revenue and expenses per 2019 budget and AMID’s five-year forecast $1.50 / Boe fee for Nearly Headless Nick additional tie-in well at Delta House, representing the anchor producer rate per AMID management $4.3 million of G&A savings in 2019E and $5.6 million of G&A savings in 2020E – 2023E and removed the direct allocation of corporate G&A from the asset segment level and shifted it to the corporate level Growth Projects: Expansion of Longview facility for $70.0 million, an increase of $13.0 million since the February 5 Meeting to account for customer’s request for purity ethane Incremental compression for AlaTenn for $6.5 million The Bamagas Ascend connection for $1.6 million Acquisitions: Acquisition of the Pascagoula Gas Plant for $36.3 million in April 2019 Financing Assumptions: Revolving credit facility maturing on September 5, 2019 is extended at the same terms Refinancing of 8.50% 2021 Senior Notes at the same terms - Also, per management, 2021 Senior Notes assumed to be registered and remain at 8.50% interest rate Excess cash flow utilized to repay revolving credit facility Distribution policy No common cash distributions after Q3 2018 and preferred equity distributions PIK Source: AMID management 32 Preliminary Draft Subject to Change AMID Financial Projections AMID Financial Projections – Assumptions Set forth below are the pricing assumptions incorporated in the AMID Financial Projections: Years Ending December 31, 2018A 2019E 2020E 2021E 2022E 2023E Natural Gas $/MMBtu $3.16 $2.74 $2.73 $2.65 $2.66 $2.73 Crude Oil $/Bbl 64.77 55.61 56.50 55.12 54.17 53.78 Mont Belvieu NGLs Ethane $/Gal $0.33 $0.30 $0.28 $0.27 $0.27 $0.27 Propane $/Gal 0.88 0.66 0.64 0.63 0.63 0.64 Isobutane $/Gal 1.09 0.80 0.73 0.72 0.71 0.70 Normal Butane $/Gal 1.02 0.79 0.72 0.72 0.72 0.71 Pentanes + $/Gal 1.43 1.15 1.15 1.11 1.10 1.09 Condensate $/Gal 1.43 1.15 1.15 1.11 1.10 1.09 Strip Pricing as of March 7, 2019 Henry Hub Natural Gas $/MMBtu $3.14 $2.96 $2.79 $2.64 $2.64 $2.73 WTI Crude Oil $/Bbl 64.82 58.06 58.12 56.24 54.95 54.32 Source: AMID management 33

Preliminary Draft Subject to Change AMID Financial Projections AMID Financial Projections –Assumptions (cont’d) Business / Segment AMID Financial Projections A? 55 wells annually connected to the Lavaca system ? 5 – 10 wells connected annually to the Yellow Rose system, resulting in run-rate volumes of 17 MMcfd Gathering & Processing? 1 – 2 wells connected annually to the Longview system? 1 well connected annually to the Chapel Hill system B? 1.2 Bcfd of firm transportation ? Midla / MLGT rate increase on Natchez lateral to $17.64 per Dth/ month in April 2019 from current rate of $8.82 Dth/month and an Natural Gas Transportation additional increase to $26.47 Dth/month in April 2021? Additional compression installed at AlaTenn in 2019 at project cost of $6.5 million and incremental EBITDA of $1.6 million C ? 10.0% annual decline in volumes Offshore Pipelines ? 12 days of hurricane downtime per year (excl. Delta House) ? 5.0% unplanned downtime in addition to known platform turnarounds D? Includes new tie back to BWOLF, Red Zinger and two additional new tiebacks (including Nearly Headless Nick) in 2021 & 2022, the first at a lower type curve, the second at a higher type curve with both at the anchor producer rate of $1.50 / Boe per AMID Delta House management ? 2019 volumes based upon production data provided by LLOG reduced by 5% for unplanned downtime and 12 hurricane days? 2020E – 2023E production profile based upon Nov-18 NSAI P50 reserves study E? 2019E South Texas volume of 13 MBpd, 2020E – 2023E volume of 14 MBpd? 2019E liquids trucking volume of 2.4 MBpd, 2020E – 2023E volume of 2.4 MBpd Trucking ? Elimination of Texas Panhandle trucking in January 2019 (Texas Panhandle + South Texas) Source: AMID management 34 Preliminary Draft Subject to Change AMID Financial Projections AMID Financial Projections –Assumptions (cont’d) Business / Segment AMID Financial Projections F? Volume reaches peak of 10 MBpd gathered and 7 MBpd trucked in 2020E Bakken Crude Gathering & ? 16.6% annual decline in volumes beginning in January 2021E Marketing G? The following well connect schedule 2019E 2020E 2021E 2022E 2023E Approach 2.8 6.1 6.1 6.1 6.1 Silver Dollar EP 9.1 24.3 24.3 24.3 24.3 (including West Texas Trucking Discovery 19.0 35.3 30.4 30.4 30.4 Henry 3.0 4.0 15.0 13.1 12.2 and Marketing) Hunt 6.0 4.0 6.1 6.1 6.1 Earthstone 8.0 7.0 3.0 3.0 3.0 Not included in financial Sequitur -- 2.0 3.0 3.0 3.0 Other -- 12.2 12.2 12.2 12.2 projections as of Wells Connected 47.9 94.9 100.2 98.3 97.3 February 5 Meeting H? Maintenance underway and is scheduled to be completed in 2H 2019 Cushing ? Revenue reduced at Cushing until maintenance completed in 2H 2019 Terminal I ? 35 MBpd throughput at Cayenne through July 2020, 1% monthly decline in volumes thereafter NGL JV Interests? 2% annual decline in Tri-State volumes beginning in January 2021? 1% monthly decline in Wilprise volumes beginning in January 2021 (Wilprise, Tri-States, Cayenne) Source: AMID management 35

Preliminary Draft Subject to Change AMID Financial Projections Identified Growth Opportunities (Included in AMID Financial Projections) ($ in millions) Implied Run-Incremental Incremental Rate EBITDA Project Description Growth Capex EBITDA Multiple Improve proportion of on-spec processing and rail volumes 2019 $43.0 $ – –Longview Build additional truck / rail sales outlets 1 2020 27.0 6.8 10.4x Expansion Secure Y-grade volumes via pipe and increase fractionation capacity and capabilities for purity products 2021 – 11.6 6.1x In August 2018, AMID announced an agreement with 2019 $36.3 $4.8 7.5x Acquisition of Enterprise for a 25% stake in the Pascagoula gas plant Interest in Comprises three trains with approximately 1.5 Bcfd of 2020 – 7.1 5.1x 2 processing capacity Pascagoula Conditions include completion of modifications to certain Gas Plant facilities on the High Point system 2021 – 6.7 5.4x Potential to add incremental compression 2019 $6.5 $0.1 NM AlaTenn 2020 – 0.7 9.5x 3 Compression 2021 – 1.0 6.5x Bamagas – Lateral pipeline connection to Ascend 2019 $0.7 $0.4 3.7x 4 Ascend 2020 – 0.6 2.6x Connection 2021 – 0.7 2.4x Source: AMID management, public filings 36 Preliminary Draft Subject to Change AMID Financial Projections Summary Financial Overview – AMID Financial Projections ($ in millions) Asset EBITDA / Adjusted EBITDA / Pro Forma Adjusted EBITDA (2018A only) $264.0 / $214.1 $249.8 / $194.7 $4.5 $252.4 / $202.5 $245.8 / $195.8 $15.7 $4.5 $15.2 $4.4 $15.5 $4.5 $229.1 / $179.1 $223.8 / $184.0 / $159.1 $3.6 $14.4 $10.0 $19.3 $3.8 $4.5 $2.9 $22.0 $13.4 $25.1 $22.3 $23.5 $22.1 $2.1 $11.1 $25.2 $22.7 $1.3 $26.0 $16.1 $38.6 $26.0 $27.9 $59.7 $68.6 $24.5 $71.8 $73.1 $86.7 $63.5 $40.2 $47.7 $44.3 $34.4 $79.6 $75.5 $74.5 $66.1 $60.9 $53.9 1 1 2018A 2019E 2020E 2021E 2022E 2023E 1 Offshore Pipelines (Includes Distributions from Destin and Okeanos) Distributions from Delta House Natural Gas Gathering and Processing Natural Gas Transportation Silver Dollar Pipeline Bakken Crude Oil Gathering NGL Pipeline JV Distributions Terminals Trucking Source: AMID Management 1. Distribution based on preceding quarter’s free cash flow 37

Preliminary Draft Subject to Change AMID Financial Projections Summary Financial Overview –AMID Financial Projections (cont’d) ($ in millions, except for per unit amounts) Capital Expenditures & Acquisitions Distributable Cash Flow / DCF per LP Unit 2018A-2023E $129.5 CAGR: 19.6% $124.1 $121.9 $120.5 $125.1 $121.2 $108.2 $98.3 $115.8 $151.0 $99.2 $125.6 $69.2 $72.9 $95.2 $86.3 $79.9 $55.0 $41.5 $37.6 $36.6 $34.6 $31.5 $30.6 2018A 2019E 2020E 2021E 2022E 2023E 2018A 2019E 2020E 2021E 2022E 2023E DCF per $0.70 $1.21 $1.51 $1.41 $1.34 $1.07 As of February 5 Meeting LP Unit1, 2 $0.79 $1.49 $1.48 $1.40 $1.29 $1.07 As of February 5 Meeting Consolidated Debt / Pro Forma Adjusted EBITDA1 6.7x 6.6x 5.8x 5.0x 4.9x 4.5x 4.5x 3.5x 5.0x 4.8x 4.6x 2.8x 4.3x 4.3x 2.5x 2.7x 2.7x 2.9x 3.2x 3.0x 2.5x 2.2x 1.8x 1.6x 2018A 2019E 2020E 2021E 2022E 2023E Senior Secured Unsecured As of February 5 Meeting Source: AMID Management 1. Pro forma for sale of refined products terminals to Sunoco, LP and assumes cash proceeds used to repay revolving credit facility and fund growth capital expenditures 2. Assumes conversion of Series A-1, Series A-2 and Series C Preferred Units convert into 23,359,144 common units and 679,290 common units are issued per quarter beginning in Q4 2018 for accrued and unpaid distributions on an as-converted basis 38 Preliminary Draft Subject to Change AMID Financial Projections AMID Financial Projections ($ in millions, except per unit metrics) For the Years Ending December 31, CAGR 2018A 2019E 2020E 2021E 2022E 2023E 2018A - 2023E Offshore Pipelines (Distributions from Destin and Okeanos)1 $79.6 $75.5 $74.5 $66.1 $60.9 $53.9 Distributions from Delta House1 40.2 86.7 63.5 47.7 44.3 34.4 Natural Gas Gathering and Processing 24.5 38.6 59.7 68.6 71.8 73.1 Natural Gas Transportation 27.9 22.3 23.5 25.2 26.0 26.0 Silver Dollar Pipeline 16.1 10.0 19.3 22.0 22.1 22.7 Bakken Crude Oil Gathering 1.3 3.6 4.4 3.8 2.9 2.1 NGL Pipeline JV Distributions1 11.1 15.2 15.7 15.5 14.4 13.4 Terminals 25.1 (1.1) 4.5 4.5 4.5 4.5 Trucking (1.9) (1.1) (1.0) (1.0) (1.0) (1.0) Asset EBITDA $223.8 $249.8 $264.0 $252.4 $245.8 $229.1 0.5% Less: Corporate G&A (56.4) (55.0) (49.8) (49.8) (49.8) (49.8) Less: Delta House Distribution Support 17.7 -- -- -- -- -- Less: Other (1.1) (0.1) (0.1) (0.1) (0.1) (0.1) Adjusted EBITDA $184.0 $194.7 $214.1 $202.5 $195.8 $179.1 (0.5%) Less: Refined Products and Marine Terminals EBITDA (24.9) -- -- -- -- -- Pro Forma Adjusted EBITDA $159.1 $194.7 $214.1 $202.5 $195.8 $179.1 2.4% Less: Interest Expense (73.8) (76.4) (73.3) (67.2) (62.4) (59.3) Less: Preferred Distributions (25.1) -- -- -- -- --Less: Maintenance Capital Expenditures (16.0) (19.9) (11.3) (11.2) (11.5) (11.5) Pro Forma Distributable Cash Flow $44.2 $98.3 $129.5 $124.1 $121.9 $108.2 19.6% Distributable Cash Flow $69.2 $98.3 $129.5 $124.1 $121.9 $108.2 Distributed Cash Flow Common Units - Public $25.1 $-- $-- $-- $-- $--Common Units - Parent 8.2 -- -- -- -- --GP 0.4 -- -- -- -- -- Distributed Cash Flow $33.8 $-- $-- $-- $-- $-- Current IDR Tier 1.3% 1.3% 1.3% 1.3% 1.3% 1.3% % to GP 1.3% 1.3% 1.3% 1.3% 1.3% 1.3% GP IDRs $-- $-- $-- $-- $-- $--Weighted Average LP Units Outstanding 54.0 54.7 55.1 55.4 55.7 66.3 Weighted Average LP Units Outstanding – As Converted2 60.0 80.4 83.5 86.6 89.6 102.9 DCF / LP Unit3 $1.26 $1.66 $1.99 $1.94 $1.91 $1.61 5.0% Distribution per LP Unit 0.62 -- -- -- -- -- NA DCF / LP Unit – As Converted2 3 $0.70 $1.21 $1.51 $1.41 $1.34 $1.07 8.7% Distribution per LP Unit 0.62 -- -- -- -- -- NA LP Coverage 2.04x NA NA NA NA NA Total Coverage 2.05 NA NA NA NA NA Source: AMID Management 1. Distribution based on preceding quarter’s free cash flow 2. Assumes conversion of Series A-1, Series A-2 and Series C Preferred Units convert into 23,359,144 common units and 679,290 common units are issued per quarter beginning in Q4 2018 for accrued and unpaid distributions on an as-converted basis 3. Pro forma for sale of refined products terminals to Sunoco, LP 39

Preliminary Draft Subject to Change AMID Financial Projections AMID Financial Projections (cont’d) ($ in millions) For the Years Ending December 31, 2018A 2019E 2020E 2021E 2022E 2023E Sources Distributable Cash Flow Surplus / (Shortfall) $98.3 $129.5 $124.1 $121.9 $108.2 Asset Sales -- -- -- -- -- Cash from Balance Sheet -- -- -- -- -- Total Sources $98.3 $129.5 $124.1 $121.9 $108.2 Uses Growth Capital Expenditures $94.8 $68.6 $30.4 $26.1 $25.1 Acquisition of Pascagoula Gas Plant 36.3 -- -- -- --Sale of Blackwater Tax Payment 23.7 -- -- -- --Amortization of Non-Recourse Debt 4.0 4.2 6.3 6.5 6.7 Other Expenses 13.6 2.7 1.8 1.4 1.3 Change in Revolver (73.2) 54.2 85.7 88.2 75.5 Cash to Balance Sheet 0.0 0.0 0.0 0.0 0.0 Other (0.9) (0.1) (0.0) (0.2) (0.4) Total Uses $98.3 $129.5 $124.1 $121.9 $108.2 Capitalization Cash $9.1 $9.1 $9.1 $9.1 $9.1 $9.1 Revolving Credit Facility 514.8 588.0 533.8 448.1 359.9 284.4 Midla / TransUnion Notes 87.8 83.7 79.6 73.3 66.7 60.0 8.500% Senior Notes 425.0 425.0 425.0 425.0 425.0 425.0 Letter of Credit 39.0 39.0 39.0 39.0 39.0 39.0 Net Debt $1,057.5 $1,126.7 $1,068.4 $976.3 $881.6 $799.4 Credit Metrics1 Total Consolidated Debt / Pro Forma Adjusted EBITDA 6.7x 5.8x 5.0x 4.9x 4.5x 4.5x Net Consolidated Debt / Pro Forma Adjusted EBITDA 6.6 5.8 5.0 4.8 4.5 4.5 Senior Secured / Pro Forma Adjusted EBITDA 3.2 3.0 2.5 2.2 1.8 1.6 First Lien Leverage 3.2x 3.2x 2.6x 2.3x 1.9x 1.7x Total Covenant Leverage 5.8 5.5 4.7 4.5 4.2 4.2 Source: AMID Management 1. Pro forma for sale of refined products terminals to Sunoco, LP and assumes cash proceeds used to repay revolving credit facility and fund growth capital expenditures 40 Preliminary Draft Subject to Change V. Preliminary Valuation

Preliminary Draft Subject to Change Preliminary Valuation Summary Valuation – AMID Common Unit ($ in millions, except per unit amounts) For Reference Only Total Partnership Sum of the Parts Peer Trading Analysis Peer Trading Analysis MLP Premiums Paid Discounted Cash Flow Discounted Cash Flow Precedent M&A Analysis Analysis Analysis 2019E 2020E 2019E 2020E $20.00 Consideration: $5.25 per Common Unit As of February 5Meeting Implied MLP Premiums Paid based on September 27, 2018 Implied MLP Premiums Paid based on January 3, 2018 $15.00 Implied MLP Premiums Paid based on September 27, 2018 as of February 5 Meeting Implied MLP Premiums Paid based on January 3, 2018 as of February 5 Meeting $10.00 $8.10 $8.12 $6.70 $6.40 $6.34 $5.46 $5.67 $5.75 $5.00 $5.32 $5.74 $3.58 $3.02 $2.99 $3.47 $3.50 $3.08 $2.30 $1.98 $0.48 $0.96 $0.46 $--$-- $-- $-- $-- $-- $-- $0.20 ($5.00) Adjusted 2019E EBITDA Adjusted 2019E EBITDA Adjusted 2020E EBITDA Adjusted 2019E EBITDA Adjusted 2019E EBITDA Adjusted 2019E EBITDA Adjusted 2020E EBITDA $194.7 $194.7 $214.1 $194.7 $194.7 $194.7 $214.1 Adjusted 2023E EBITDA Adjusted 2023E EBITDA Adjusted 2020E EBITDA $183.6 $183.6 $214.1 41 Preliminary Draft Subject to Change Preliminary Valuation Valuation Methodologies The following sets forth the methodologies utilized by Evercore in its preliminary valuation of AMID Common Units, each assuming a June 30, 2019 valuation date. Methodology Description Metrics/Assumptions ? Values AMID common units based on the concept of the ? Discounted the projected cash flows to the assumed June 30, 2019 effective date time value of money? EBITDA exit multiple of 8.0x to 10.0x (consistent with natural gas gathering and ? Utilizing the AMID Financial Projections herein, Evercore: processing, offshore and diversified master limited partnerships (“MLPs”) valuations ? Utilized varying WACC discount rates and over an extended period of time) Total Company applied various perpetuity growth rates to derive ? Perpetuity growth rate of 1.75% to 2.25% Discounted after-tax valuation ranges for AMID? WACC of 9.5% to 10.5% based on capital asset pricing model (“CAPM”) for natural Cash Flow ? Calculated terminal values based on a range of gathering processing, offshore and diversified MLPs Analysis multiples of EBITDA as well as assumed ? Unitholder effective tax rate of 29.6% (80.0% at 37.0% top bracket) from 2019E to perpetuity growth rates 2023E and a terminal value tax rate of 37.0% ? For the terminal value, tax depreciation assumed to be equal to maintenance capital expenditures ? Values AMID common units based on current market ? Enterprise value / EBITDA multiples applied to 2019E and 2020E adjusted EBITDA enterprise value multiples of relevant EBITDA of selected for all EBITDA excluding Delta House Total Company comparable natural gas gathering and processing, offshore ? Enterprise value / EBITDA multiples applied to 2025E Delta House EBITDA, based Peer Group and diversified MLPs on stepdown in anchor rate from $4.50 per Boe to $1.50 per Boe in 2020E, Trading Analysis expiration of fixed gathering revenues in 2022E and peak production of second tie-in well in 2025E; Delta House cash flows from June 30, 2019E to 2024E in excess of 2025E cash flow levels discounted at 8.5% WACC ? Values AMID common units based the sum of the ? Discounted the projected cash flows to the assumed June 30, 2019 effective date Sum of the Parts valuation of each business unit and corporate liabilities ? WACC based on CAPM of similar assets Discounted Cash implied by the discounted cash flow of each business unit ? Unitholder effective tax rate of 29.6% (80.0% at 37.0% top bracket) from 2019E to Flow Analysis and the company as a whole 2023E and a terminal value tax rate of 37.0% ? For the terminal value, tax depreciation assumed to be equal to maintenance capital expenditures Sum of the Parts? Values AMID common units based the sum of the ? Enterprise value / EBITDA multiples applied to 2019E and 2020E EBITDA Precedent M&A valuation of each business unit and corporate liabilities Analysis implied by historical transactions of similar assets? Values AMID common units based the sum of the ? Enterprise value / EBITDA multiples applied to 2019E and 2020E EBITDA Sum of the Parts valuation of each business unit and corporate liabilities Peer Group implied by the current market enterprise value multiples of Trading Analysis relevant EBITDA for MLPs with similar assets For Premiums Paid ? Values AMID common units based on historical premiums? Median 30-Day, 60-Day and 90-Day premiums paid applied to relevant unit prices Reference Only Analysis? paid in (i) MLP buy-ins and (ii) MLP mergers since 2011 42

Preliminary Draft Subject to Change Preliminary Valuation Summary Valuation – Total Partnership Analysis – AMID Common Unit Peer Trading Analysis Peer Trading Analysis Discounted Cash Flow Analysis 2019E 2020E $15.00 $11.00 $7.00 $5.46 $5.32 $3.58 $3.00 $3.08 $1.98 $0.48 $-- $-- $-- ($1.00) As of February 5 Meeting ($5.00) 9.5% – 10.5% WACC 2019E Multiple Range Selected 2020E Multiple Range Selected 2023E EBITDA Perpetuity Growth All Assets Other than Delta House: All Assets Other than Delta House: Multiple: Rate: 2019E EBITDA Multiple: 2020E EBITDA Multiple: 8.0x – 10.0x 1.75% – 2.25% 8.5x – 10.5x 7.5x – 9.5x Delta House: 2025E EBITDA Multiple: 8.0x – 10.0x June 30, 2019E – December 31, 2024E Cash Flow in Excess of 2025E Cash Flow Discounted at Midpoint 8.5% WACC Source: AMID Management 43 Preliminary Draft Subject to Change Preliminary Valuation Discounted Cash Flow Analysis – Assumptions Evercore utilized the following assumptions to analyze AMID’s discounted cash flows: Discounted the projected cash flows to June 30, 2019 EBITDA and capital expenditures through December 31, 2023E per the AMID Financial Projections assuming no asset sales Unitholder effective tax rate of 29.6% (80.0% of taxable income at 37.0% tax bracket) Mid-point discount rate of 10.0% utilizing WACC based on CAPM Terminal value based on a (i) 8.0x to 10.0x EBITDA exit multiple and (ii) 1.75% to 2.25% perpetuity growth rate Tax depreciation assumed to equal maintenance capital expenditures in perpetuity 44

Preliminary Draft Subject to Change Preliminary Valuation Total Partnership – Discounted Cash Flow Analysis ($ in millions, except per unit amounts) AMID Financial Projections For the Six Months Ending December 31, For the Years Ending December 31, EBITDA Perpetuity 2019E 2020E 2021E 2022E 2023E Multiple Growth Adjusted EBITDA $103.4 $214.1 $202.5 $195.8 $179.1 $179.1 $179.1 Less: Tax Depreciation and Amortization (1,514.4) (79.9) (41.5) (37.6) (29.3) (11.5) EBIT ($1,411.1) $134.2 $161.0 $158.3 $149.8 $167.6 Less: Cash Taxes -- (6.4) (7.6) (7.5) (7.1) (62.0) EBIAT ($1,411.1) $127.8 $153.3 $150.8 $142.7 $105.6 Plus: Tax Depreciation and Amortization 1,514.4 79.9 41.5 37.6 29.3 11.5 Less: Growth Capital Expenditures (58.2) (68.6) (30.4) (26.1) (25.1) --Less: Maintenance Capital Expenditures (8.2) (11.3) (11.2) (11.5) (11.5) (11.5) Unlevered Free Cash Flow $37.0 $127.8 $153.3 $150.8 $135.4 $105.6 EBITDA Multiple / Perpetuity Growth Rate 9.0x 2.0% Terminal Value $1,612.1 $1,346.1 PV of Terminal Value @ 10.0% Discount Rate $1,049.9 $876.6 Plus: PV of Unlevered Free Cash Flow @ 10.0% Discount Rate 484.8 Implied Enterprise Value $1,534.7 $1,361.4 Less: Estimated Net Debt outstanding as of June 30, 2019 (1,132.4) Less: Liquidation Value of Series A-1 Convertible Preferred Units as of June 30, 2019 (147.5) Less: Liquidation Value of Series A-2 Convertible Preferred Units as of June 30, 2019 (63.2) Less: Liquidation Value of Series C Convertible Preferred Units as of June 30, 2019 (141.8) Total Common Equity Value $49.7 ($123.6) Estimated Total Units Outstanding as of June 30, 20191 54.6 Value per LP Unit $0.91 ($2.26) Sensitivity Analysis EBITDA Multiple Perpetuity Growth Rate 7.0x 8.0x 9.0x 10.0x 11.0x 1.75% 1.75% 2.00% 2.25% 2.25% 9.0% ($2.55) ($0.33) $1.90 $4.12 $6.35 9.0% $0.28 $0.28 $0.98 $1.74 $1.74 9.5% (2.96) (0.78) 1.40 3.58 5.76 WACC 9.5% (1.35) (1.35) (0.75) (0.10) (0.10) WACC 10.0% (3.36) (1.23) 0.91 3.04 5.18 10.0% (2.79) (2.79) (2.26) (1.70) (1.70) 10.5% (3.75) (1.66) 0.43 2.52 4.61 10.5% (4.06) (4.06) (3.60) (3.11) (3.11) 11.0% (4.13) (2.09) (0.04) 2.01 4.06 11.0% (5.19) (5.19) (4.79) (4.36) (4.36) 1. Includes 1,049,659 general partner units estimated outstanding as of June 30, 2019 and an additional 465,979 LTIP units issued in Q1 2019 and Q2 2019 45 Preliminary Draft Subject to Change Preliminary Valuation Peer Group Trading ($ in millions, except per unit or share amounts) Price Equity Enterprise Enterprise Value / EBITDA Distribution Yield Distribution Total Partnership / Corporation 3/7/19 Value Value 2019E 2020E Current 2019E Growth Return Offshore Pipelines Plains All American Pipeline, L.P. $23.97 $17,416.1 $28,851.1 10.5x 10.4x 5.0% 5.5% 9.6% 14.6% Genesis Energy, L.P. 21.63 2,650.5 6,834.2 9.8 9.3 10.0% 10.2% 0.5% 10.4% Shell Midstream Partners, L.P. 18.57 4,241.0 6,174.2 8.2 6.8 8.6% 9.3% 4.4% 13.0% Mean 9.5x 8.8x 7.9% 8.3% 4.8% 12.7% Median 9.8 9.3 8.6% 9.3% 4.4% 13.0% Natural Gas Gathering and Processing CNX Midstream Partners LP $15.29 $993.1 $1,534.2 7.2x 6.2x 9.4% 10.3% 8.8% 18.2% Crestwood Equity Partners LP 32.05 2,282.6 4,828.3 10.2 8.9 7.5% 7.5% 3.6% 11.0% DCP Midstream Partners, LP 31.49 4,605.2 10,691.6 8.9 7.9 9.9% 9.9% 1.6% 11.5% Enable Midstream Partners, LP 15.01 6,503.0 11,173.0 9.8 9.5 8.5% 8.5% 3.7% 12.2% Hess Midstream Partners LP 22.82 1,270.9 1,236.3 11.2 9.2 6.5% 7.1% 11.3% 17.8% Noble Midstream Partners LP 36.66 1,458.6 2,751.1 10.2 7.4 6.4% 7.2% 17.7% 24.1% Summit Midstream Partners, LP 10.45 874.7 2,740.9 8.5 8.1 22.0% 22.0% NM NM Targa Resources Corp. 40.09 9,306.6 15,929.7 12.8 10.2 9.1% 9.1% 3.3% 12.3% Mean 9.9x 8.4x 9.9% 10.2% 7.1% 15.3% Median 10.0 8.5 8.8% 8.8% 3.7% 12.3% Source: FactSet, Public filings 46

Preliminary Draft Subject to Change Preliminary Valuation Total Partnership – Peer Group Trading Analysis ($ in millions, except per unit amounts) 2019E Summary Results Adjusted 2019E EBITDA $194.7 Less: 2019E Class A Distributions from Delta House (86.7) Run Rate 2019E Adjusted EBITDA $107.9 Relevant EBITDA Multiple 8.5x - 10.5x Implied Enterprise Value (All Assets Other than Delta House) $917.4 - $1,133.2 2025E Delta House EBITDA1 $25.5 Relevant EBITDA Multiple 8.5x - 10.5x Implied Delta House Enterprise Value $216.8 - $267.8 A Plus: Present Value of Delta House Cash Flows from June 30, 2019E to December 31, 2024E in excess of 2025E Cash Flows at 8.5% 110.3 Less: Estimated Net Debt outstanding as of June 30, 2019 (1,132.4) Less: Liquidation Value of Series A-1 Convertible Preferred Units as of June 30, 2019 (147.5) Less: Liquidation Value of Series A-2 Convertible Preferred Units as of June 30, 2019 (63.2) Less: Liquidation Value of Series C Convertible Preferred Units as of June 30, 2019 (141.8) Total Common Equity Value ($240.5) - $26.3 Estimated Total Units Outstanding as of June 30, 20192 54.6 Value per LP Unit ($4.40) - $0.48 2020E Summary Results Adjusted 2020E EBITDA $214.1 Less: 2020E Class A Distributions from Delta House (63.5) Run Rate 2020E Adjusted EBITDA $150.6 Relevant EBITDA Multiple 7.5x - 9.5x Implied Enterprise Value (All Assets Other than Delta House) $1,129.5 - $1,430.7 2025E Delta House EBITDA1 $25.5 Relevant EBITDA Multiple 7.5x - 9.5x Implied Delta House Enterprise Value $191.3 - $242.3 A Plus: Present Value of Delta House Cash Flows from June 30, 2019E to December 31, 2024E in excess of 2025E Cash Flows at 8.5% 110.3 Less: Estimated Net Debt outstanding as of June 30, 2019 (1,132.4) Less: Liquidation Value of Series A-1 Convertible Preferred Units as of June 30, 2019 (147.5) Less: Liquidation Value of Series A-2 Convertible Preferred Units as of June 30, 2019 (63.2) Less: Liquidation Value of Series C Convertible Preferred Units as of June 30, 2019 (141.8) Total Common Equity Value ($53.9) - $298.3 Estimated Total Units Outstanding as of June 30, 20192 54.6 Value per LP Unit ($0.99) - $5.46 1. Inclusive of deferred revenue 2. Includes 1,049,659 general partner units estimated outstanding as of June 30, 2019 and an additional 465,979 LTIP units issued in Q1 2019 and Q2 2019 47 Preliminary Draft Subject to Change Preliminary Valuation A Present Value of Incremental Class A Delta House Cash Flows ($ in millions) For the Six Months Ending December 31, For the Years Ending December 31, 2019E 2020E 2021E 2022E 2023E 2024E Cash Flows Attributable to Class A Holders (35.65%) $40.9 $63.7 $48.0 $44.5 $34.6 $27.9 Less: 2025E Class A Cash Flows (35.65%) (12.1) (24.3) (24.3) (24.3) (24.3) (24.3) Incremental Cash Flow $28.7 $39.5 $23.7 $20.2 $10.4 $3.6 Present Value of 2019E – 2025E Cash Flow in Excess of 2025E Cash Flow @ 8.5% Discount Rate $110.3 48

Preliminary Draft Subject to Change Preliminary Valuation Summary – Sum of the Parts – Discounted Cash Flow Analysis ($ in millions, except for per unit amounts) Assumptions Divestiture Sale EBITDA Exit Perpetuity Growth Resulting Enterprise Value Range Changes Since February 5 Meeting Implied 2018A EBITDA Multiple Price Assumption WACC Range Multiple Range Rate Range Low High Low High Low High 1 1 2 Natural Gas Gathering and Processing 7.5% – 8.5% 7.0x – 9.0x 0.75% – 1.25% $428.1 $592.9 ($2.6) $43.8 11.1x - 15.4x $130.0 Natural Gas Transportation 10.0% – 11.0% 9.0 – 11.0 1.75% – 2.25% 165.5 255.7 (14.1) 21.9 5.9 - 9.2 200.0 Offshore Pipelines excl. Delta House 8.0% – 9.0% 6.0 – 8.0 (1.00%) – 1.00% 450.2 581.7 12.9 27.7 5.5 3 - 7.1 3 Delta House 8.0% – 9.0% 2.0 – 4.0 (11.00%) – (9.00%) 258.6 315.6 (23.4) (22.2) 4.0 - 4.9 Bakken Crude Oil Gathering 12.0% – 13.0% 7.0 – 9.0 1.75% – 2.25% 17.9 22.7 2.2 1.2 13.8 - 17.4 30.0 Silver Dollar Pipeline 9.5% – 10.5% 7.0 – 9.0 1.75% – 2.25% 147.3 183.1 23.8 (1.1) 9.1 - 11.4 125.0 Cushing Terminal 10.0% – 11.0% 8.0 – 10.0 1.75% – 2.25% 31.7 42.7 (3.5) (3.4) N.M. - N.M. 30.0 NGL JV Interests 8.0% – 9.0% 10.0 – 12.0 1.75% – 2.25% 129.8 163.6 (1.2) (0.8) 9.4 - 11.8 Crude Oil Trucking4 -- 5.0 -- -- N.M. - N.M. Total Enterprise Value (Pre Corporate G&A) $1,629.1 $2,163.0 ($5.8) $67.0 6.7x 8.9x Less: Value of Corporate G&A 8.4% – 9.4% 8.8x – 10.6x 1.75% – 2.25% (422.9) (513.2) (18.4) 0.9 Total Enterprise Value $1,206.2 $1,649.8 ($24.2) $67.7 5.0x - 6.8x Less: Estimated Net Debt outstanding as of June 30, 2019 (1,132.4) Less: Liquidation Value of Series A-1 Convertible Preferred Units as of June 30, 2019 (147.5) Less: Liquidation Value of Series A-2 Convertible Preferred Units as of June 30, 2019 (63.2) Less: Liquidation Value of Series C Convertible Preferred Units as of June 30, 2019 (141.8) Total Common Equity Value ($278.8) $164.8 Estimated Total Units Outstanding as of June 30, 20195 54.6 Value per LP Unit ($5.10) $3.02 Incremental Value of Divestitures6 ($288.1) ($75.5) Estimated Total Units Outstanding as of June 30, 20195 54.6 Incremental Value per LP Unit ($5.27) ($1.38) Value per LP Unit Adjusted for Divestitures ($10.37) $1.63 Note: Blended weighted average WACC and EBITDA multiple from peer trading comps (excluding Delta House) applied to value of corporate G&A valuation 1. Based on 2019E EBITDA 2. Assumes divestiture of Chatom Bazor Ridge and Lavaca for $130.0 million 3. Based on 4Q 2018 annualized EBITDA 4. Assumes liquidation value of zero to $5.0 million 5. Includes 1,049,659 general partner units estimated outstanding as of June 30, 2019 and an additional 465,979 LTIP units issued in Q1 2019 and Q2 2019 6. Assumes $232.5 to $330.6 million valuation for Chatom Bazor Ridge and Lavaca based on the impact of the sale of Chatom Bazor Ridge and Lavaca on the valuation of Natural Gas Gathering and Processing resulting from the Discounted Cash Flow Analysis 49 Preliminary Draft Subject to Change Preliminary Valuation Summary – Sum of the Parts – Precedent M&A Analysis ($ in millions, except for per unit amounts) Assumptions Divestiture Sale 2019E EBITDA 2020E EBITDA Resulting Enterprise Value Range1 Changes Since February 5 Meeting Implied 2018A EBITDA Multiple Price Assumption Multiple Range Multiple Range Low High Low High Low High Natural Gas Gathering and Processing 7.0x – 9.0x 7.0x – 9.0x $234.3 $447.7 ($42.4) $17.5 6.1x 2 - 11.6x 2 $130.0 3 Natural Gas Transportation 9.0 – 11.0 9.0 – 11.0 186.8 236.0 21.4 25.0 6.7 - 8.5 200.0 Offshore Pipelines excl. Delta House 6.0 – 8.0 6.0 – 8.0 433.8 589.2 29.0 2.3 5.3 - 7.2 5 Delta House4 258.6 315.6 (23.4) (22.2) 4.0 5 - 4.9 Bakken Crude Oil Gathering 7.0 – 9.0 7.0 – 9.0 19.2 34.9 (0.1) 4.4 14.7 - 26.8 30.0 Silver Dollar Pipeline 7.0 – 9.0 7.0 – 9.0 56.3 135.5 (0.1) 25.3 3.5 - 8.4 125.0 Cushing Terminal 8.0 – 10.0 32.5 40.7 (0.3) (0.4) N.M. - N.M. 30.0 NGL JV Interests 10.0 – 12.0 10.0 – 12.0 145.8 179.7 2.9 0.0 10.5 - 13.0 Crude Oil Trucking6 -- 5.0 -- -- N.M. - N.M. Total Enterprise Value (Pre Corporate G&A) $1,367.3 $1,984.1 ($12.9) $51.7 5.6x - 8.2x Less: Value of Corporate G&A 7.4x – 9.3x 7.4x – 9.3x (336.3) (508.9) (26.4) (85.7) Total Enterprise Value $1,031.0 $1,475.2 ($39.3) ($34.0) 4.2x - 6.1x Less: Estimated Net Debt outstanding as of June 30, 2019 (1,132.4) Less: Liquidation Value of Series A-1 Convertible Preferred Units as of June 30, 2019 (147.5) Less: Liquidation Value of Series A-2 Convertible Preferred Units as of June 30, 2019 (63.2) Less: Liquidation Value of Series C Convertible Preferred Units as of June 30, 2019 (141.8) Total Common Equity Value ($454.0) ($9.8) Estimated Total Units Outstanding as of June 30, 20197 54.6 Value per LP Unit ($8.31) ($0.18) Incremental Value of Divestitures8 ($153.2) $86.7 Estimated Total Units Outstanding as of June 30, 20197 54.6 Incremental Value per LP Unit ($2.80) $1.59 Value per LP Unit Adjusted for Divestitures ($11.11) $1.41 Note: Blended weighted average WACC and EBITDA exit multiple (excluding Delta House) applied to value of corporate G&A valuation 1. Future enterprise value and capital expenditures discounted to the present value using midpoint of WACC range for each segment utilized in the Discounted Cash Flow analyses 2. Based on 2019E EBITDA 3. Assumes divestiture of Chatom Bazor Ridge and Lavaca for $130.0 million 4. Based on Discounted Cash Flow Analysis 5. Based on 4Q 2018 annualized EBITDA 6. Assumes liquidation value of zero to $5.0 million 7. Includes 1,049,659 general partner units estimated outstanding as of June 30, 2019 and an additional 465,979 LTIP units issued in Q1 2019 and Q2 2019 8. Assumes $135.6 million to $222.3 million valuation for Chatom Bazor Ridge and Lavaca based on impact of the sale of Chatom Bazor Ridge and Lavaca on the valuation of Natural Gas Gathering and Processing resulting from Precedent M&A Analysis 50

Preliminary Draft Subject to Change Preliminary Valuation Summary – Sum of the Parts – Peer Trading Analysis – 2019E ($ in millions, except for per unit amounts) Assumptions Divestiture Sale 2019E EBITDA Resulting Enterprise Value Range Changes Since February 5 Meeting Implied 2018A EBITDA Multiple Price Assumption Multiple Range Low High Low High Low High Natural Gas Gathering and Processing 9.0x – 11.0x $347.1 $424.3 ($51.5) ($21.2) 9.0x 1 - 11.0x 1 $130.0 2 Natural Gas Transportation 9.5 – 10.5 212.3 234.6 20.4 22.5 7.6 - 8.4 200.0 Offshore Pipelines excl. Delta House 8.0 – 10.0 601.3 751.6 2.3 2.8 7.4 - 9.2 Delta House3 258.6 315.6 (23.4) (22.2) 4.0 4 - 4.9 4 Bakken Crude Oil Gathering 8.0 – 10.0 22.5 28.2 0.0 (0.0) 17.3 - 21.7 30.0 Silver Dollar Pipeline 8.0 – 10.0 79.7 99.6 10.5 13.1 4.9 - 6.2 125.0 Cushing Terminal5 7.0 – 8.0 31.4 35.9 (2.3) (4.5) N.M. - N.M. 30.0 NGL JV Interests 11.0 – 13.0 168.1 198.7 7.6 7.7 12.1 - 14.4 Crude Oil Trucking6 -- 5.0 -- -- N.M. - N.M. Total Enterprise Value (Pre-Corporate G&A) $1,721.2 $2,093.6 ($36.2) ($1.7) 7.1x - 8.6x Less: Value of Corporate G&A 8.8x – 10.6x (483.1) (583.1) (81.3) (107.3) Total Enterprise Value $1,238.0 $1,510.4 ($117.6) ($109.1) 5.1x - 6.2x Less: Estimated Net Debt outstanding as of June 30, 2019 (1,132.4) Less: Liquidation Value of Series A-1 Convertible Preferred Units as of June 30, 2019 (147.5) Less: Liquidation Value of Series A-2 Convertible Preferred Units as of June 30, 2019 (63.2) Less: Liquidation Value of Series C Convertible Preferred Units as of June 30, 2019 (141.8) Total Common Equity Value ($247.0) $25.4 Estimated Total Units Outstanding as of June 30, 20197 54.6 Value per LP Unit ($4.52) $0.46 Incremental Value of Divestitures8 ($86.4) ($12.6) Estimated Total Units Outstanding as of June 30, 20197 54.6 Incremental Value per LP Unit ($1.58) ($0.23) Value per LP Unit Adjusted for Divestitures ($6.10) $0.23 Note: Blended weighted average WACC and EBITDA exit multiple (excluding Delta House) applied to value of corporate G&A valuation 1. Based on 2019E EBITDA 2. Assumes divestiture of Chatom Bazor Ridge and Lavaca for $130.0 million 3. Based on Discounted Cash Flow Analysis 4. Based on 4Q 2018 annualized EBITDA 5. Cushing Terminal Valuation is based on 2020E EBITDA 6. Assumes liquidation value of zero to $5.0 million 7. Includes 1,049,659 general partner units estimated outstanding as of June 30, 2019 and an additional 465,979 LTIP units issued in Q1 2019 and Q2 2019 8. Assumes $192.4 million to $235.1 million valuation for Chatom Bazor Ridge and Lavaca based on the impact of the sale of Chatom Bazor Ridge and Lavaca on the valuation of Natural Gas Gathering and Processing in the 2019E Peer Trading Analysis 51 Preliminary Draft Subject to Change Preliminary Valuation Summary – Sum of the Parts – Peer Trading Analysis – 2020E ($ in millions, except for per unit amounts) Assumptions Divestiture Sale 2020E EBITDA Resulting Enterprise Value Range Changes Since February 5 Meeting Implied 2018A EBITDA Multiple Price Assumption Multiple Range Low High Low High Low High 1 1 2 Natural Gas Gathering and Processing 8.0x – 9.0x $477.7 $537.4 ($23.5) ($26.4) 12.4x - 13.9x $130.0 Natural Gas Transportation 9.0 – 11.0 211.4 258.3 42.3 46.9 7.6 - 9.3 200.0 Offshore Pipelines excl. Delta House 7.5 – 10.0 588.3 784.4 27.9 74.6 7.2 - 9.6 4 4 Delta House3 258.6 315.6 (23.4) (22.2) 4.0 - 4.9 Bakken Crude Oil Gathering 7.5 – 9.5 32.7 41.4 4.7 5.9 25.1 - 31.8 30.0 Silver Dollar Pipeline 7.5 – 9.5 144.7 183.2 40.6 51.3 9.0 - 11.4 125.0 Cushing Terminal 7.0 – 8.0 31.4 35.9 (2.3) (4.5) N.M. - N.M. 30.0 NGL JV Interest 9.5 – 11.5 150.2 181.9 7.9 7.9 10.9 - 13.1 Crude Oil Trucking5 -- 5.0 -- -- N.M. - N.M. Total Enterprise Value (Pre Corporate G&A) $1,895.0 $2,343.1 $74.2 $133.6 7.8x - 9.6x Less: Value of Corporate G&A 8.0x – 9.9x (399.1) (492.2) (32.1) (47.4) Total Enterprise Value $1,495.9 $1,851.0 $42.1 $86.2 6.1x - 7.6x Less: Estimated Net Debt outstanding as of June 30, 2019 (1,132.4) Less: Liquidation Value of Series A-1 Convertible Preferred Units as of June 30, 2019 (147.5) Less: Liquidation Value of Series A-2 Convertible Preferred Units as of June 30, 2019 (63.2) Less: Liquidation Value of Series C Convertible Preferred Units as of June 30, 2019 (141.8) Total Common Equity Value $10.9 $366.0 Estimated Total Units Outstanding as of June 30, 20196 54.6 Value per LP Unit $0.20 $6.70 Incremental Value of Divestitures7 ($281.3) ($151.7) Estimated Total Units Outstanding as of June 30, 20196 54.6 Incremental Value per LP Unit ($5.15) ($2.78) Value per LP Unit Adjusted for Divestitures ($4.95) $3.92 Note: Blended weighted average WACC and EBITDA exit multiple (excluding Delta House) applied to value of corporate G&A valuation 1. Based on 2019E EBITDA 2. Assumes divestiture of Chatom Bazor Ridge and Lavaca for $130.0 million 3. Based on Discounted Cash Flow Analysis 4. Based on 4Q 2018 annualized EBITDA 5. Assumes liquidation value of zero to $5.0 million 6. Includes 1,049,659 general partner units estimated outstanding as of June 30, 2019 and an additional 465,979 LTIP units issued in Q1 2019 and Q2 2019 7. Assumes $246.6 million to $277.4 million valuation for Chatom Bazor Ridge and Lavaca based on the impact of the sale of Chatom Bazor Ridge and Lavaca on the valuation of Natural Gas Gathering and Processing in the 2020E Peer Trading Analysis 52

Preliminary Draft Subject to Change Preliminary Valuation Precedent MLP Buy-ins and Midstream Mergers For Reference Only Selected MLP Buy-ins Premium1 Date 1-Day 30-Day 60-Day 90-Day Announced Acquiror(s) / Target Consideration Prior Spot VWAP VWAP VWAP 02/05/19 SunCoke Energy, Inc. / SunCoke Energy Partners, L.P. Stock-for-Unit 9.3% 31.2% 26.5% 18.9% 07/10/18 ArcLight Energy Partners Fund VI, L.P. / TransMontaigne Partners L.P. Cash-for-Unit 13.5% 8.6% 8.2% 10.2% 11/08/18 Western Gas Equity Partners, LP / Western Gas Partners, LP Unit-for-Unit 7.6% 13.8% 9.3% 5.9% 10/22/18 EnLink Midstream, LLC / EnLink Midstream Partners, LP Unit-for-Unit 1.1% (0.6%) 1.5% 5.8% 10/19/18 Valero Energy Corporation / Valero Energy Partners LP Cash-for-Unit 6.0% 11.9% 10.9% 10.2% 10/09/18 Antero Midstream GP LP / Antero Midstream Partners LP Cash/Stock-for-Unit 18.6% 6.6% 7.3% 8.2% 10/08/18 Navios Maritime Acquisition Corp. / Navios Maritime Midstream Partners, LP2 Stock-for-Unit 9.3% 4.8% (1.4%) (5.8%) 08/01/18 Energy Transfer Equity, L.P. / Energy Transfer Partners, L.P. Unit-for-Unit 11.2% 19.2% 22.3% 27.4% 05/17/18 The Williams Companies, Inc. / Williams Partners L.P.3 Stock-for-Unit 13.6% 5.8% 1.0% 3.4% 05/17/18 Enbridge Inc. / Enbridge Energy Partners, L.P. Stock-for-Unit 13.9% 15.9% 10.4% 0.8% 05/17/18 Enbridge Inc. / Spectra Energy Partners, LP Stock-for-Unit 20.8% 18.7% 13.7% 7.6% 03/26/18 Tallgrass Energy GP, LP / Tallgrass Energy Partners, L.P.4 Stock-for-Unit 0.1% 6.4% 9.2% 8.7% 01/02/18 Archrock, Inc. / Archrock Partners, L.P. Stock-for-Unit 23.4% 27.7% 21.6% 18.6% 06/02/17 World Point Terminals, Inc. / World Point Terminals, LP Cash-for-Unit 5.8% 3.4% 3.2% 3.5% 05/18/17 Energy Transfer Partners, LP / PennTex Midstream Partners, LP Cash-for-Unit 20.1% 19.9% 22.6% 24.4% 03/02/17 VTTI B.V. / VTTI Energy Partners LP Cash-for-Unit 6.0% 6.8% 14.2% 13.5% 02/01/17 ONEOK, Inc. / ONEOK Partners, L.P. Stock-for-Unit 25.8% 22.4% 26.2% 29.0% 01/27/17 Enbridge Energy Co, Inc. / Midcoast Energy Partners, L.P. Cash-for-Unit (8.6%) 5.4% 11.3% 5.8% Median 10.3% 10.2% 10.7% 8.4% Mean 11.0% 12.7% 12.1% 10.9% Selected Midstream Mergers Premium1 Date 1-Day 30-Day 60-Day 90-Day Announced Acquiror(s) / Target Consideration Prior Spot VWAP VWAP VWAP 04/26/18 EQT Midstream Partners, LP / Rice Midstream Partners LP Unit-for-Unit 9.8% 12.5% 6.1% 2.9% 08/29/17 Zenith Energy U.S., L.P. / Arc Logistics Partners LP Cash-for-Unit 15.2% 12.3% 12.1% 12.2% 08/14/17 Andeavor Logistics LP / Western Refining Logistics, LP Unit-for-Unit 6.4% NA NA NA Median 9.8% 12.4% 9.1% 7.5% Source: Bloomberg, FactSet, public filings Mean 10.5% 12.4% 9.1% 7.5% 1. VWAP premiums paid are calculated by dividing the value of the offer, defined as the exchange ratio multiplied by the closing price of the acquiror’s shares / units on the last trading day prior to announcement plus any cash received, by the 30, 60 or 90 trading day VWAP of the target as calculated from the last undisturbed trading day prior to the announcement 2. VWAP premiums paid are calculated by dividing the value of the offer, defined as the exchange ratio multiplied by the closing price of the acquiror’s shares on the last trading day prior to announcement by the 30, 60 or 90 trading day VWAP of the target as calculated from the last trading day prior to the announcement 3. VWAP premiums paid is calculated by dividing the value of the offer, defined as the exchange ratio multiplied by the closing price of WMB’s shares on the last trading day prior to announcement by the 30, 60 or 90 trading day VWAP of the target as calculated from March 15, 2018, or after the FERC announcement of MLP income tax recovery disallowance 4. VWAP premiums paid is calculated by the 30, 60 or 90 trading day VWAP of acquiror divided by the 30, 60 or 90 trading day VWAP of the target multiplied by the exchange ratio 53 Preliminary Draft Subject to Change Preliminary Valuation Premiums Paid Analysis For Reference Only Premiums Paid 1-Day Spot 30-Day VWAP 60-Day VWAP 90-Day VWAP AMID Common Unit Price $5.75 $6.28 $6.91 $7.49 of Historical MLP Merger Premium Range (8.6%) – 25.8% (0.6%) – 27.7% (1.4%) – 26.2% (5.8%) – 29.0% As 2018 Implied AMID Common Unit Price Range $5.26 – $7.24 $6.25 – $8.02 $6.82 – $8.73 $7.05 – $9.66 Median MLP Merger Premium 10.3% 10.2% 10.7% 8.4% September 27, Median Implied Transaction Price $6.34 $6.93 $7.65 $8.12 1-Day Spot 30-Day VWAP 60-Day VWAP 90-Day VWAP of AMID Common Unit Price $3.15 $4.31 $5.01 $5.31 As 2019 Historical MLP Merger Premium Range (8.6%) – 25.8% (0.6%) – 27.7% (1.4%) – 26.2% (5.8%) – 29.0% January 3, Implied AMID Common Unit Price Range $2.88 – $3.96 $4.29 – $5.51 $4.94 – $6.32 $5.00 – $6.85 Median MLP Merger Premium 10.3% 10.2% 10.7% 8.4% Median Implied Transaction Price $3.47 $4.76 $5.54 $5.75 Source: Bloomberg 54

Preliminary Draft Subject to Change VI. Illustrative AMID Unitholder Tax Analysis Preliminary Draft Subject to Change Illustrative AMID Unitholder Tax Analysis AMID Unitholder Tax Analysis @ Illustrative Offer Price ($5.25 / unit) – Assumptions PricewaterhouseCoopers LLP (“PwC”) provided the AMID unaffiliated unitholders tax liability by unit acquisition date information, which included the following: Adjusted Basis – Represents the weighted average price acquired, plus cumulative income, less cumulative distributions and DD&A from the acquisition date to January 2018 §751 Gain – Recharacterization of gain or loss on the sale of a partnership interest from capital to ordinary on §751 property owned by the partnership Net Ordinary Gain / (Loss) per Unit – Calculated as §751 Gain less Passive Loss Carryover assuming Passive Loss Carryover amounts are 100% available to offset Ordinary Gains Net Capital Gain / (Loss) per Unit – Calculated as Total Gain / (Loss) per Unit less §751 Gain Estimated Taxes – Calculated based on the Net Ordinary Gain / Loss per Unit and Net Capital Gain / (Loss) per Unit assuming the unitholder tax rates as set forth in table below Type Ordinary Gain Tax Rate (T1) Capital Gain Tax Rate (T2) Individual 29.6% 20.0% Corporation 21.0% 21.0% Partnership 29.6% 20.0% Estate 29.6% 20.0% Trust 29.6% 20.0% Foreign 21.0% 21.0% UBTI 21.0% 21.0% Other 29.6% 20.0% 55

Preliminary Draft Subject to Change Illustrative AMID Unitholder Tax Analysis AMID Unitholder Tax Analysis by Year Acquired @ $5.25 per Unit Ordinary Gain / (Loss) Total Gain / (Loss) Per Unit Per Unit Capital Gain / (Loss) Per Unit Tax Liability Per Unit A B C = A - B D E F = D + E C D G = C – D H = F * T1 I = G * T2 J = H + I Average Ordinary Tax Capital Tax Total Tax % of Total Purchase Offer Adjusted Total Gain / Carryover Net Ordinary Total Gain / Net Capital Liability / Liability / Liability / Year AMID Units Units Price Price Basis (Loss) 751 Gain Passive Losses Gain / (Loss) (Loss) 751 Gain Gain / (Loss) (Benefit) (Benefit) (Benefit) 2011 431,098 1.1% $19.53 $5.25 ($16.76) $22.01 $9.41 ($19.76) ($10.35) $22.01 $9.41 $12.60 ($3.02) $2.52 ($0.50) 2012 443,166 1.2% 19.44 5.25 (11.96) 17.21 8.74 (20.29) (11.55) 17.21 8.74 8.47 (3.16) 1.72 (1.44) 2013 826,804 2.2% 18.62 5.25 (9.89) 15.14 6.16 (19.36) (13.21) 15.14 6.16 8.98 (3.15) 1.86 (1.29) 2014 3,036,352 7.9% 21.94 5.25 0.10 5.15 6.30 (15.13) (8.83) 5.15 6.30 (1.15) (2.46) (0.23) (2.69) 2015 5,309,239 13.9% 11.30 5.25 (6.55) 11.80 5.67 (12.77) (7.10) 11.80 5.67 6.13 (1.76) 1.26 (0.50) 2016 14,537,257 38.0% 8.90 5.25 (4.71) 9.96 4.63 (10.06) (5.43) 9.96 4.63 5.33 (1.47) 1.08 (0.39) 2017 12,799,597 33.5% 13.03 5.25 4.11 1.14 3.16 (6.81) (3.64) 1.14 3.16 (2.03) (0.94) (0.41) (1.35) 2018 823,557 2.2% 11.85 5.25 6.15 (0.90) 2.13 (4.67) (2.53) (0.90) 2.13 (3.03) (0.73) (0.61) (1.34) Total / Wtd. Avg. 38,207,069 100.0% $12.16 $5.25 ($1.73) $6.98 $4.50 ($10.06) ($5.57) $6.98 $4.50 $2.48 ($1.47) $0.51 ($0.96) 56 Preliminary Draft Subject to Change Illustrative AMID Unitholder Tax Analysis AMID Unitholder Tax Analysis by Month Acquired @ $5.25 per Unit Ordinary Gain / (Loss) Total Gain / (Loss) Per Unit Per Unit Capital Gain / (Loss) Per Unit Tax Liability Per Unit A B C = A - B D E F = D + E C G H = C – G H = F * T1 I = G * T2 J = H + I Average Ordinary Tax Capital Tax Total Tax % of Total Purchase Offer Adjusted Total Gain / Carryover Net Ordinary Total Gain / Net Capital Liability / Liability / Liability / Month AMID Units Units Price Price Basis (Loss) 751 Gain Passive Losses Gain / (Loss) (Loss) 751 Gain Gain / (Loss) (Benefit) (Benefit) (Benefit) 08/2011 267,696 0.7% $20.79 $5.25 ($18.69) $23.94 $9.45 ($20.11) ($10.66) $23.94 $9.45 $14.49 ($3.14) $2.90 ($0.24) 09/2011 43,331 0.1% 16.26 5.25 (14.12) 19.37 9.39 (18.50) (9.11) 19.37 9.39 9.98 (2.62) 2.01 (0.61) 10/2011 57,668 0.2% 18.13 5.25 (13.21) 18.46 9.45 (19.46) (10.00) 18.46 9.45 9.01 (2.88) 1.81 (1.07) 11/2011 15,581 0.0% 17.70 5.25 (13.45) 18.70 9.26 (19.27) (10.01) 18.70 9.26 9.44 (2.92) 1.89 (1.03) 12/2011 46,821 0.1% 17.66 5.25 (13.63) 18.88 9.19 (19.41) (10.22) 18.88 9.19 9.69 (2.91) 1.95 (0.96) 01/2012 56,514 0.1% 17.95 5.25 (13.18) 18.43 9.16 (19.52) (10.36) 18.43 9.16 9.27 (2.87) 1.87 (0.99) 02/2012 32,048 0.1% 18.89 5.25 (12.62) 17.87 8.96 (19.90) (10.94) 17.87 8.96 8.91 (2.84) 1.82 (1.02) 03/2012 29,013 0.1% 20.50 5.25 (11.88) 17.13 8.89 (20.76) (11.87) 17.13 8.89 8.24 (3.33) 1.66 (1.67) 04/2012 125,148 0.3% 21.10 5.25 (11.16) 16.41 8.82 (21.08) (12.27) 16.41 8.82 7.60 (3.54) 1.53 (2.01) 05/2012 5,848 0.0% 21.26 5.25 (10.97) 16.22 8.74 (21.05) (12.31) 16.22 8.74 7.48 (2.59) 1.57 (1.01) 06/2012 68,628 0.2% 18.90 5.25 (12.45) 17.70 8.67 (20.17) (11.51) 17.70 8.67 9.03 (3.41) 1.81 (1.60) 07/2012 33,425 0.1% 19.20 5.25 (11.86) 17.11 8.59 (20.31) (11.72) 17.11 8.59 8.51 (2.74) 1.76 (0.98) 08/2012 17,585 0.0% 19.79 5.25 (11.18) 16.43 8.50 (20.23) (11.73) 16.43 8.50 7.93 (2.79) 1.64 (1.15) 09/2012 14,311 0.0% 19.20 5.25 (11.66) 16.91 8.41 (20.11) (11.70) 16.91 8.41 8.50 (2.71) 1.76 (0.94) 10/2012 26,589 0.1% 18.65 5.25 (11.54) 16.79 8.46 (19.88) (11.43) 16.79 8.46 8.34 (2.85) 1.71 (1.13) 11/2012 11,265 0.0% 18.96 5.25 (11.23) 16.48 8.36 (19.88) (11.52) 16.48 8.36 8.13 (2.86) 1.67 (1.19) 12/2012 22,793 0.1% 15.94 5.25 (13.08) 18.33 8.10 (18.70) (10.61) 18.33 8.10 10.23 (3.10) 2.05 (1.04) 01/2013 38,986 0.1% 14.57 5.25 (13.66) 18.91 7.82 (18.35) (10.53) 18.91 7.82 11.09 (2.54) 2.29 (0.25) 02/2013 30,849 0.1% 15.95 5.25 (12.38) 17.63 7.76 (18.45) (10.70) 17.63 7.76 9.88 (2.83) 2.01 (0.82) 03/2013 27,598 0.1% 16.66 5.25 (12.41) 17.66 7.81 (19.19) (11.39) 17.66 7.81 9.86 (3.27) 1.98 (1.29) 04/2013 85,157 0.2% 16.60 5.25 (12.15) 17.40 7.74 (19.30) (11.56) 17.40 7.74 9.65 (2.60) 2.01 (0.59) 05/2013 123,566 0.3% 16.53 5.25 (11.29) 16.54 5.82 (18.37) (12.55) 16.54 5.82 10.72 (2.84) 2.23 (0.61) 06/2013 162,294 0.4% 18.95 5.25 (9.67) 14.92 5.77 (19.37) (13.60) 14.92 5.77 9.16 (3.51) 1.87 (1.64) 07/2013 98,261 0.3% 20.55 5.25 (8.70) 13.95 5.68 (20.24) (14.55) 13.95 5.68 8.27 (3.23) 1.72 (1.51) 08/2013 98,280 0.3% 19.64 5.25 (9.08) 14.33 5.60 (19.70) (14.10) 14.33 5.60 8.73 (3.05) 1.83 (1.22) 09/2013 76,460 0.2% 19.79 5.25 (9.15) 14.40 5.46 (20.13) (14.67) 14.40 5.46 8.94 (3.31) 1.86 (1.45) 10/2013 23,935 0.1% 19.95 5.25 (8.94) 14.19 5.32 (20.30) (14.98) 14.19 5.32 8.87 (3.87) 1.81 (2.06) 11/2013 52,058 0.1% 19.94 5.25 (4.80) 10.05 5.08 (17.64) (12.56) 10.05 5.08 4.97 (3.47) 0.90 (2.58) 12/2013 9,360 0.0% 22.25 5.25 (7.31) 12.56 5.05 (20.98) (15.93) 12.56 5.05 7.52 (4.48) 1.52 (2.96) 01/2014 98,255 0.3% 22.41 5.25 (3.09) 8.34 7.23 (17.37) (10.13) 8.34 7.23 1.11 (2.92) 0.22 (2.70) 02/2014 82,749 0.2% 25.87 5.25 (1.30) 6.55 7.27 (19.04) (11.77) 6.55 7.27 (0.72) (2.90) (0.15) (3.05) 03/2014 41,914 0.1% 24.11 5.25 (2.62) 7.87 7.22 (18.83) (11.61) 7.87 7.22 0.65 (3.29) 0.13 (3.15) 04/2014 113,220 0.3% 24.13 5.25 (2.37) 7.62 7.14 (18.82) (11.69) 7.62 7.14 0.48 (3.12) 0.10 (3.02) 05/2014 310,048 0.8% 25.37 5.25 (1.02) 6.27 7.00 (18.70) (11.69) 6.27 7.00 (0.73) (3.44) (0.15) (3.58) 06/2014 139,500 0.4% 26.67 5.25 (0.49) 5.74 6.67 (19.54) (12.87) 5.74 6.67 (0.93) (2.92) (0.19) (3.11) 07/2014 38,645 0.1% 28.62 5.25 1.15 4.10 6.60 (20.25) (13.65) 4.10 6.60 (2.50) (3.72) (0.51) (4.23) 08/2014 49,223 0.1% 27.81 5.25 1.23 4.02 6.52 (19.30) (12.79) 4.02 6.52 (2.50) (3.30) (0.51) (3.81) 09/2014 937,032 2.5% 29.59 5.25 2.03 3.22 6.51 (20.34) (13.83) 3.22 6.51 (3.29) (4.09) (0.66) (4.75) 10/2014 47,707 0.1% 28.50 5.25 1.73 3.52 6.56 (20.01) (13.45) 3.52 6.56 (3.04) (3.41) (0.62) (4.03) 11/2014 1,082,778 2.8% 12.38 5.25 (0.55) 5.80 5.56 (7.44) (1.88) 5.80 5.56 0.25 (0.42) 0.05 (0.37) 57

Preliminary Draft Subject to Change Illustrative AMID Unitholder Tax Analysis AMID Unitholder Tax Analysis by Month Acquired @ $5.25 per Unit Ordinary Gain / (Loss) Total Gain / (Loss) Per Unit Per Unit Capital Gain / (Loss) Per Unit Tax Liability Per Unit A B C = A - B D E F = D + E C G H = C – G H = F * T1 I = G * T2 J = H + I Average Ordinary Tax Capital Tax Total Tax % of Total Purchase Offer Adjusted Total Gain / Carryover Net Ordinary Total Gain / Net Capital Liability / Liability / Liability / Month AMID Units Units Price Price Basis (Loss) 751 Gain Passive Losses Gain / (Loss) (Loss) 751 Gain Gain / (Loss) (Benefit) (Benefit) (Benefit) 12/2014 95,280 0.2% $20.70 $5.25 ($0.27) $5.52 $6.22 ($14.78) ($8.56) $5.52 $6.22 ($0.70) ($2.38) ($0.14) ($2.52) 01/2015 381,468 1.0% 14.86 5.25 (4.13) 9.38 5.68 (13.05) (7.38) 9.38 5.68 3.70 (1.78) 0.76 (1.02) 02/2015 239,550 0.6% 16.55 5.25 (5.77) 11.02 5.82 (16.10) (10.28) 11.02 5.82 5.19 (2.99) 1.04 (1.95) 03/2015 202,794 0.5% 17.15 5.25 (4.81) 10.06 5.77 (16.14) (10.36) 10.06 5.77 4.29 (3.07) 0.86 (2.21) 04/2015 290,539 0.8% 15.02 5.25 (5.81) 11.06 5.60 (15.14) (9.54) 11.06 5.60 5.46 (2.75) 1.10 (1.65) 05/2015 119,048 0.3% 12.50 5.25 (4.23) 9.48 5.37 (11.27) (5.90) 9.48 5.37 4.11 (1.44) 0.84 (0.60) 06/2015 113,234 0.3% 13.35 5.25 (4.09) 9.34 5.32 (11.95) (6.64) 9.34 5.32 4.02 (1.58) 0.83 (0.75) 07/2015 155,373 0.4% 15.36 5.25 (5.13) 10.38 5.48 (15.23) (9.75) 10.38 5.48 4.90 (2.51) 1.00 (1.50) 08/2015 294,672 0.8% 12.11 5.25 (6.74) 11.99 5.75 (13.58) (7.83) 11.99 5.75 6.24 (1.90) 1.29 (0.62) 09/2015 411,749 1.1% 9.98 5.25 (5.70) 10.95 5.37 (10.89) (5.52) 10.95 5.37 5.58 (1.45) 1.13 (0.32) 10/2015 2,323,787 6.1% 9.78 5.25 (7.73) 12.98 5.82 (12.67) (6.84) 12.98 5.82 7.15 (1.54) 1.49 (0.05) 11/2015 335,578 0.9% 8.89 5.25 (6.08) 11.33 5.39 (10.25) (4.86) 11.33 5.39 5.94 (1.19) 1.21 0.02 12/2015 441,447 1.2% 8.47 5.25 (6.99) 12.24 5.43 (11.08) (5.64) 12.24 5.43 6.81 (1.50) 1.39 (0.11) 01/2016 1,297,532 3.4% 4.88 5.25 (8.41) 13.66 5.10 (8.95) (3.85) 13.66 5.10 8.56 (1.05) 1.74 0.69 02/2016 1,643,686 4.3% 6.13 5.25 (7.21) 12.46 4.94 (9.01) (4.06) 12.46 4.94 7.52 (1.17) 1.51 0.35 03/2016 1,475,594 3.9% 4.49 5.25 (6.85) 12.10 4.50 (7.41) (2.92) 12.10 4.50 7.60 (0.79) 1.54 0.75 04/2016 602,390 1.6% 4.93 5.25 (6.91) 12.16 4.69 (7.99) (3.30) 12.16 4.69 7.47 (0.84) 1.54 0.70 05/2016 1,089,840 2.9% 8.69 5.25 (5.45) 10.70 5.16 (10.25) (5.09) 10.70 5.16 5.54 (1.25) 1.14 (0.11) 06/2016 623,433 1.6% 9.52 5.25 (4.12) 9.37 5.00 (10.11) (5.11) 9.37 5.00 4.37 (1.44) 0.89 (0.55) 07/2016 575,649 1.5% 10.79 5.25 (3.76) 9.01 4.75 (11.06) (6.32) 9.01 4.75 4.27 (1.70) 0.87 (0.83) 08/2016 635,891 1.7% 9.56 5.25 (3.67) 8.92 4.52 (9.77) (5.25) 8.92 4.52 4.40 (1.29) 0.90 (0.39) 09/2016 3,831,444 10.0% 11.51 5.25 (3.20) 8.45 4.52 (11.61) (7.08) 8.45 4.52 3.93 (2.02) 0.79 (1.23) 10/2016 781,682 2.0% 9.59 5.25 (2.62) 7.87 3.81 (9.16) (5.34) 7.87 3.81 4.05 (1.46) 0.82 (0.64) 11/2016 1,047,467 2.7% 12.52 5.25 (2.23) 7.48 4.30 (11.66) (7.36) 7.48 4.30 3.18 (1.92) 0.65 (1.27) 12/2016 932,651 2.4% 11.72 5.25 (1.97) 7.22 4.29 (10.95) (6.66) 7.22 4.29 2.93 (1.58) 0.60 (0.98) 01/2017 1,327,151 3.5% 14.27 5.25 0.86 4.39 4.54 (10.74) (6.19) 4.39 4.54 (0.15) (1.36) (0.03) (1.40) 02/2017 568,455 1.5% 15.19 5.25 4.00 1.25 3.49 (8.51) (5.01) 1.25 3.49 (2.24) (1.21) (0.47) (1.68) 03/2017 928,501 2.4% 13.34 5.25 2.81 2.44 3.24 (7.85) (4.61) 2.44 3.24 (0.80) (1.25) (0.16) (1.41) 04/2017 1,754,948 4.6% 14.35 5.25 4.94 0.31 3.05 (7.14) (4.09) 0.31 3.05 (2.74) (1.15) (0.55) (1.70) 05/2017 789,873 2.1% 14.35 5.25 5.38 (0.13) 2.95 (6.70) (3.75) (0.13) 2.95 (3.09) (0.99) (0.63) (1.62) 06/2017 2,148,456 5.6% 12.05 5.25 3.80 1.45 3.15 (5.98) (2.83) 1.45 3.15 (1.70) (0.75) (0.35) (1.10) 07/2017 1,075,846 2.8% 11.20 5.25 3.73 1.52 3.14 (5.61) (2.47) 1.52 3.14 (1.62) (0.67) (0.33) (1.00) 08/2017 1,100,931 2.9% 12.60 5.25 5.06 0.19 2.74 (5.68) (2.94) 0.19 2.74 (2.55) (0.73) (0.52) (1.25) 09/2017 790,298 2.1% 12.75 5.25 5.28 (0.03) 2.47 (5.61) (3.14) (0.03) 2.47 (2.51) (0.78) (0.51) (1.30) 10/2017 293,259 0.8% 12.85 5.25 5.15 0.10 3.08 (6.26) (3.18) 0.10 3.08 (2.98) (0.82) (0.61) (1.43) 11/2017 1,125,458 2.9% 12.50 5.25 5.22 0.03 2.95 (5.83) (2.88) 0.03 2.95 (2.93) (0.74) (0.60) (1.34) 12/2017 896,422 2.3% 11.85 5.25 4.88 0.37 2.73 (5.53) (2.80) 0.37 2.73 (2.36) (0.78) (0.48) (1.26) 01/2018 823,557 2.2% 11.85 5.25 6.15 (0.90) 2.13 (4.67) (2.53) (0.90) 2.13 (3.03) (0.73) (0.61) (1.34) Total / Wtd. Avg. 38,207,069 100.0% $12.16 $5.25 ($1.73) $6.98 $4.50 ($10.06) ($5.57) $6.98 $4.50 $2.48 ($1.47) $0.51 ($0.96) 58 Preliminary Draft Subject to Change Illustrative AMID Unitholder Tax Analysis AMID Unitholder Tax Analysis @ Illustrative Offer Price ($5.25 / unit) Implied Taxes 36.0 34.0 Tax Liability Deciles ($ per unit) 32.0 First Decile ($4.75) - ($1.95) Sixth Decile ($1.13) - ($0.99) Second Decile ($1.95) - ($1.43) Seventh Decile ($0.99) - ($0.55) 30.0 Third Decile ($1.43) - ($1.34) Eighth Decile ($0.55) - ($0.11) 28.0 Fourth Decile ($1.34) - ($1.25) Ninth Decile ($0.11) - $0.02 Fifth Decile ($1.25) - ($1.13) Tenth Decile $0.02 - $0.75 26.0 Weighted Average ($0.96) 24.0 Total Tax Liability (Benefits) of Unaffiliated Unitholders ($MM) ($36.8) 22.0 Includes all units with zero tax 20.0 consequences or net tax benefits resulting Millions) from the Merger 18.0 (in 16.0 s Unit 14.0 12.0 10.0 8.0 6.0 4.0 2.0 0.0 --$ $0.01 $0.03 $0.04 $0.05 $0.06 $0.08 $0.09 $0.10 $0.12 $0.13 $0.14 $0.16 $0.17 $0.18 $0.19 $0.21 $0.22 $0.23 $0.25 $0.26 $0.27 $0.29 $0.30 $0.31 $0.32 $0.34 $0.35 $0.36 $0.38 $0.39 $0.40 $0.42 $0.43 $0.44 $0.45 $0.47 $0.48 $0.49 $0.51 $0.52 $0.53 $0.55 $0.56 $0.57 $0.58 $0.60 $0.61 $0.62 $0.64 $0.65 $0.66 $0.68 $0.69 $0.70 $0.71 $0.73 $0.74 $0.75 $0.77 $0.78 $0.79 $0.81 $0.82 $0.83 $0.84 $0.86 $0.87 $0.88 $0.90 $0.91 $0.92 $0.94 $0.95 $0.96 $0.97 $0.99 $1.00 Net Taxes Paid per AMID Unit 59

$ ( ( $ $ ( $ ( 40 30 20 10 $ 10 20 $ 30 $ 40 $ . . . . $ 00 . . 00 . 00 00 . 00) 00) 00) 00) --3. 04) ($ 85) 3. ($ ($24.08) 8 4.0) First ($ 5) 2.5 ($ Precedent 2 .82) ($ 3. 33) ($ Decile $-- Illustrative 6. 00 $ ) 4.75 ($ ) 2 .59 ($ ($1.11) Taxable ($18.94) ) 185. ($ Second 12. 4) ($ AMID .00 0 $ 2. 64) ($ .04 3 $ MLP MLP $7.03 A Decile 1 .95) ($ .) 2 34 ($ 0 2 .2 $ Buy ($14.61) -Third 6) 2.9 ($ MLP 1 .57) ($In B $0.58 1. 23) ($ Decile 23 3. $ 3 8.1 $ Unitholder ($1.43) MLP ($108) . C 80. 3 $ ($11.18 ) Fourth ($2. )09 Tax ($1.44) Estimated $0.95 Unitholder ($0 ).95 MLP $3.61 D Decile 32 11. $ ($1.34) Cash Tax ($0. 03) $1. 05 ($2. 44) Tax MLP Fifth ($2. )90 E ($0.8 7) $1. 22 Analysis 60 ($0 .56) Impact Decile $3.70 $1 87 2. MLP ($1 5).2 (Benefit) F $0 31 . $1.51 / $0. 60 Sixth ($2 .77) ($0.44) $1. 99 MLP ($0. )36 G Decile $4 0 .0 $14 4 .9 ($1.13) Expense $0 ..71 $2.14 MLP $1 89 per . ($1. ) 23 H Seventh ($0.14) ($0 .07) $2.5 2 Unit $4. 18 Decile $15 4 .9 MLP ($0. 9)9 I $1.46 $5 .50 $4. 47 Eighth $1.01 $1.1 3 AMID $3.8 4 $0.0 1 $4 .64 Decile $16.6 8 ($0 .55) $2. 0 0 $1 7 0.0 $5. 71 Ninth $2.8 8 $1.54 $5.75 $1.0 2 Decile $5.0 5 $19 98 . ($0. 11) Subject $3. 33 to $1 5 4.3 $13.49 Preliminary $6. 11 Tenth $2. 5 4 $6. 4 9 $8. 51 Decile $5 0 Draft 7. $21. 64 Change $0.02 . (150 . (125 (100 . . (75 . (50 . (25 25 . . 50 . 75 100 . 0%) 0%) 0%) 0%) 0%) 0%) % -- 0% 0% 0% 0% (25.5%) .(8 1% ) 3%) (100. 6.7% 2 First ( ) 27 .% ( )Precedent (6. 9% ) .9(30 %) Decile --% Illustrative 41 6% . %) 61 .50 ( 1(2 .7%) (2.3%) Taxable 9%) .8(7 (1 6.5%) Second 1%) (6 . AMID % 0 .0 4.2 5%) ( MLP 1 % 6.5 MLP Decile % 7.21 A 3.34 %) ( %) 6(19. % .50 Buy Third (60%) .9 (9.4%) - In MLP %) 5 (4. B .4% 1 Estimated (11 4%) . Decile 1 7.5% 9.8% 1 Unitholder (31.8%) MLP .1%) 9 ( Cash C (46 % ) 6. 1.7% Fourth (9.2%) Tax (4.1%) Tax 2.3% Unitholder (8.8%) MLP 5% 19 . D Decile 2 7.6% (2 9.7%) Tax (0. %)3 2.2% (Benefit) (1 % ) 0.2 MLP Fifth (9 2% ) . / E (2 5%) 3 0% . . Analysis 61 (5. 2%) Impact Decile 2 % 0.1 3% 4.1 MLP (2 .9%)7 F 2.6 % Expense 3 2% . 2. 5% Sixth (8. 8%) per (1 .3% ) (cont’d) 4. 9% MLP (3. 3%) G Decile 2 7% 1. Unit 3 4% 6. (2 2%)5. 6 0% as. 4 5% . MLP 7 % % .9 (3 9%) . H Seventh (0 % ) of 4. (0. %) 6.2 % 6 2 7% 2. Decile 38. % 9 MLP (22 %) Offer 0. I 1 .3% 2 11 % .5 1 % 8.6 Eighth 3.2% 3.2% AMID 9 .4% Value 0.1% 2 2% 5. Decile 4 0.7% (1 % ) 2.2 16 8% . 21. % 1 2 3.8% Ninth 9. 2% 4. % 4 14 .1% 9 5% . Decile 2 % .73 48 % .7 (2 .4% ) Subject 28.0% to 3 0 .1 % 5 2% Preliminary 6. 1 % 59. Tenth 6. 9% 1 % .07 7 9.0% Decile 3 9% Draft 0. 5 % Change .28 0 .5%

Preliminary Draft Subject to Change Appendix Preliminary Draft Subject to Change A. Weighted Average Cost of Capital Analysis

Preliminary Draft Subject to Change Weighted Average Cost of Capital Analysis AMID Total Partnership ($ in millions, except per unit / share amounts) Unit/Share Price Market Equity Total Debt and Total Debt and Preferred Adjusted Unlevered Beta 1,2 Partnership / Corporation 3/7/19 Value Preferred Equity Equity / Total Capitalization Beta CNX Midstream Partners LP $15.29 $993 $477 32.5% 0.99 0.74 Crestwood Equity Partners LP 32.05 2,283 2,365 50.9% 0.90 0.52 DCP Midstream Partners, LP 31.49 4,605 6,383 58.1% 1.09 0.55 Natural Gas Enable Midstream Partners, LP 15.01 6,503 4,640 41.6% 0.79 0.53 Gathering and Hess Midstream Partners LP 22.82 1,271 - --% 0.96 0.96 Processing Noble Midstream Partners LP 36.66 1,459 559 27.7% 0.94 0.74 Summit Midstream Partners, LP 10.45 875 1,835 67.7% 0.87 0.35 Targa Resources Corp. 40.09 9,307 8,552 47.9% 0.97 0.56 Unlevered Beta Median 44.8% 0.95 0.56 Plains All American Pipeline, L.P. 23.97 17,416 11,501 39.8% 0.97 0.66 Genesis Energy, L.P. 21.63 2,651 4,194 61.3% 1.09 0.52 Offshore Shell Midstream Partners, L.P. 18.57 4,241 2,116 33.3% 0.81 0.60 Median 39.8% 0.97 0.60 American Midstream Partners, LP $3.84 $207 $1,348 86.7% 0.72 0.16 Historical MRP Supply-Side MRP Risk-free Rate 3 2.9% 2.9% Historical MRP (7.1%) WACC Sensitivities Unlevered Beta 0.16 0.16 Debt and Preferred / Total Capitalization 86.7% 86.7% Unlevered Beta Adjusted Levered Equity Beta 0.90 0.90/ 0.10 0.20 0.30 0.40 0.50 d on e i 30.0% 9.0% 9.7% 10.3% 11.0% 11.6% Cost of Market Risk Premium (“MRP”) 4 7.1% 6.0% Preferr izat 40.0% 9.2% 9.8% 10.4% 11.0% 11.7% Equity / WACC Small Company Risk Premium 5 5.0% 5.0% al 50.0% 9.3% 9.9% 10.5% 11.1% 11.7% t Equity Cost of Capital 6 14.3% 13.3% nd api 60.0% 9.5% 10.0% 10.6% 11.2% 11.8% C 70.0% 9.6% 10.2% 10.7% 11.3% 11.8% 7a Pre-Tax Cost of Debt 13.5% 13.5% bt 80.0% 9.7% 10.3% 10.8% 11.4% 11.9% e After-Tax Cost of Debt 2 9.5% 9.5% D Total 90.0% 9.9% 10.4% 10.9% 11.4% 11.9% WACC 10.2% 10.0% Supply-Side MRP (6.0%) WACC Sensitivities Unlevered Beta / 0.10 0.20 0.30 0.40 0.50 d Capitalization rre 30.0% 8.9% 9.5% 10.0% 10.6% 11.1% e 40.0% 9.1% 9.6% 10.1% 10.7% 11.2% 50.0% 9.2% 9.7% 10.3% 10.8% 11.3% 60.0% 9.4% 9.9% 10.4% 10.9% 11.4% and Pref 70.0% 9.5% 10.0% 10.5% 10.9% 11.4% ebt 80.0% 9.7% 10.1% 10.6% 11.0% 11.5% Source: Predicted raw betas from FactSet; Adjusted Equity Beta calculated as: (0.67) × Raw Beta + (0.33) × 1.0 D Total 90.0% 9.8% 10.2% 10.7% 11.1% 11.6% 1. Unlevered Beta calculated as: Adjusted Equity Beta × (E/(E + D × (1-T)) 2. Assumes unitholder effective tax rate of 29.6% (80.0% of 37.0% tax rate) for Partnerships and tax rate of 21.0% for Corporations 3. 20-year Treasury as of March 7, 2019 4. Source: Duff & Phelps 5. Low Cap (Decile 10x) by Duff & Phelps with a market capitalization between $166.5 million and $227.8 million 6. Equity Cost of Capital calculated as: Risk-free rate + (Levered Equity Beta × Market Risk Premium) + Small Company Risk Premium 7. Pre-Tax Cost of Debt based on yield to worst for AMID’s 8.500% 2021 Senior Unsecured Notes as of March 7, 2019, extended to 20-years by addition of 42 bps premium for U.S. Treasury maturing March 7, 2038 versus U.S. Treasury maturing March 7, 2021 62 Preliminary Draft Subject to Change Weighted Average Cost of Capital Analysis Natural Gas Gathering and Processing ($ in millions, except per unit / share amounts) Unit/Share Price Market Equity Total Debt and Total Debt and Preferred Adjusted Unlevered Corporation 3/7/19 Value Preferred Equity Equity / Total Capitalization Beta Beta 1,2 Partnership / CNX Midstream Partners LP $15.29 $993 $477 32.5% 0.99 0.74 Crestwood Equity Partners LP 32.05 2,283 2,365 50.9% 0.90 0.52 DCP Midstream Partners, LP 31.49 4,605 6,383 58.1% 1.09 0.55 Natural Gas Enable Midstream Partners, LP 15.01 6,503 4,640 41.6% 0.79 0.53 Unlevered Gathering and Hess Midstream Partners LP 22.82 1,271 - --% 0.96 0.96 Beta Processing Noble Midstream Partners LP 36.66 1,459 559 27.7% 0.94 0.74 Summit Midstream Partners, LP 10.45 875 1,835 67.7% 0.87 0.35 Targa Resources Corp. 40.09 9,307 8,552 47.9% 0.97 0.56 Median 44.8% 0.95 0.56 Historical MRP Supply-Side MRP Risk-free Rate 3 2.9% 2.9% Unlevered Beta 0.56 0.56 Historical MRP (7.1%) WACC Sensitivities Debt and Preferred / Total Capitalization 44.8% 44.8% Unlevered Beta Adjusted Levered Equity Beta 0.88 0.88 0.30 0.40 0.50 0.60 0.70 4 ed / ti on 30.0% 7.0% 7.6% 8.3% 8.9% 9.6% Cost of Market Risk Premium (“MRP”) 7.1% 6.0% r r za 35.0% 6.9% 7.5% 8.2% 8.8% 9.4% Equity / WACC Small Company Risk Premium 5 2.5% 2.5% fe e i l 6 40.0% 6.8% 7.5% 8.1% 8.7% 9.3% Equity Cost of Capital 11.6% 10.6% Pr pita a 45.0% 6.8% 7.4% 8.0% 8.6% 9.2% 7 and C 50.0% 6.7% 7.3% 7.9% 8.5% 9.1% l Pre-Tax Cost of Debt 6.2% 6.2%bt a 55.0% 6.6% 7.2% 7.8% 8.4% 9.0% After-Tax Cost of Debt 2 4.4% 4.4% De Tot 60.0% 6.5% 7.1% 7.7% 8.3% 8.8% WACC 8.3% 7.8% Supply-Side MRP (6.0%) WACC Sensitivities Unlevered Beta / 0.30 0.40 0.50 0.60 0.70 d e ation 30.0% 6.7% 7.3% 7.8% 8.4% 8.9% referr liz 35.0% 6.6% 7.2% 7.7% 8.3% 8.8% P 40.0% 6.6% 7.1% 7.6% 8.2% 8.7% Capita 45.0% 6.5% 7.0% 7.5% 8.1% 8.6% and 50.0% 6.4% 6.9% 7.4% 8.0% 8.5% al 55.0% 6.3% 6.8% 7.3% 7.8% 8.4% Debt Tot 60.0% 6.3% 6.8% 7.2% 7.7% 8.2% Source: Predicted raw betas from FactSet; Adjusted Equity Beta calculated as: (0.67) × Raw Beta + (0.33) × 1.0 1. Unlevered Beta calculated as: Adjusted Equity Beta × (E/(E + D × (1-T)) 2. Assumes unitholder effective tax rate of 29.6% (80.0% of 37.0% tax rate) for Partnerships and tax rate of 21.0% for Corporations 3. 20-year Treasury as of March 7, 2019 4. Source: Duff & Phelps 5. Low Cap (Decile 9) by Duff & Phelps with a market capitalization between $299.4 million and $656.8 million 6. Equity Cost of Capital calculated as: Risk-free rate + (Levered Equity Beta × Market Risk Premium) + Small Company Risk Premium 7. Pre-Tax Cost of Debt based on yield to worst for Natural Gas G&P peers’ Senior Unsecured Notes as of March 7, 2019 with an average maturity of December 5, 2028, extended to 20-years by addition of 15 bps premium for U.S. Treasury maturing March 7, 2038 versus U.S. Treasury maturing December 5, 2028 63

Preliminary Draft Subject to Change Weighted Average Cost of Capital Analysis Natural Gas Transportation ($ in millions, except per unit / share amounts) Unit/Share Price Market Equity Total Debt and Total Debt and Preferred Adjusted Unlevered Partnership / Corporation 3/7/19 Value Preferred Equity Equity / Total Capitalization Beta Beta 1,2 EQT Midstream Partners, LP $40.51 $8,404 $4,082 32.7% 0.88 0.65 Enable Midstream Partners, LP 15.01 6,503 4,640 41.6% 0.79 0.53 Natural Gas TC PipeLines, LP 33.72 2,454 2,072 45.8% 0.88 0.55 Unlevered Tallgrass Energy, LP 23.35 6,544 3,206 32.9% 0.69 0.50 Transportation Beta The Williams Companies, Inc. 26.94 32,745 22,449 40.7% 1.01 0.65 Median 40.7% 0.88 0.55 Historical MRP Supply-Side MRP Historical MRP (7.1%) WACC Sensitivities Risk-free Rate 3 2.9% 2.9% Unlevered Beta 0.55 0.55 Unlevered Beta 0.30 0.40 0.50 0.60 0.70 Debt and Preferred / Total Capitalization 40.7% 40.7% on Adjusted Levered Equity Beta 0.82 0.82 red / at i 30.0% 9.9% 10.6% 11.2% 11.9% 12.5% er ef i z 35.0% 9.6% 10.2% 10.8% 11.5% 12.1% Cost of 4 r al 40.0% 9.2% 9.9% 10.5% 11.1% 11.7% Market Risk Premium (“MRP”) 7.1% 6.0% 45.0% 8.9% 9.5% 10.1% 10.7% 11.4% Equity / WACC Small Company Risk Premium 5 7.0% 7.0% nd P Capit a 50.0% 8.6% 9.2% 9.8% 10.4% 11.0% Equity Cost of Capital 6 15.6% 14.8% al 55.0% 8.2% 8.8% 9.4% 10.0% 10.6% 7 Debt Tot 60.0% 7.9% 8.5% 9.0% 9.6% 10.2% Pre-Tax Cost of Debt 5.2% 5.2% After-Tax Cost of Debt 2 3.7% 3.7% Supply-Side MRP (6.0%) WACC Sensitivities WACC 10.8% 10.3% Unlevered Beta / 0.30 0.40 0.50 0.60 0.70 d e ation 30.0% 9.6% 10.2% 10.7% 11.3% 11.8% referr liz 35.0% 9.3% 9.8% 10.4% 10.9% 11.5% P 40.0% 9.0% 9.5% 10.0% 10.6% 11.1% Capita 45.0% 8.6% 9.2% 9.7% 10.2% 10.7% and 50.0% 8.3% 8.8% 9.3% 9.8% 10.4% al 55.0% 8.0% 8.5% 9.0% 9.5% 10.0% Debt Tot 60.0% 7.6% 8.1% 8.6% 9.1% 9.6% Source: Predicted raw betas from FactSet; Adjusted Equity Beta calculated as: (0.67) × Raw Beta + (0.33) × 1.0 1. Unlevered Beta calculated as: Adjusted Equity Beta × (E/(E + D × (1-T)) 2. Assumes unitholder effective tax rate of 29.6% (80.0% of 37.0% tax rate) for Partnerships and tax rate of 21.0% for Corporations 3. 20-year Treasury as of March 7, 2019 4. Source: Duff & Phelps 5. Low Cap (Decile 10y) by Duff & Phelps with a market capitalization between $87.6 million and $166.3 million 6. Equity Cost of Capital calculated as: Risk-free rate + (Levered Equity Beta × Market Risk Premium) + Small Company Risk Premium 7. Pre-Tax Cost of Debt based on yield to worst for Natural Gas Transportation peers’ Senior Unsecured Notes as of March 7, 2019 with an average maturity of February 6, 2032, extended to 20-years by addition of 11 bps premium for U.S. Treasury maturing March 7, 2038 versus U.S. Treasury maturing February 6, 2032 64 Preliminary Draft Subject to Change Weighted Average Cost of Capital Analysis Offshore Pipelines ($ in millions, except per unit amounts) Unit/Share Price Market Equity Total Debt and Total Debt and Preferred Adjusted Unlevered 1,2 Partnership / Corporation 3/7/19 Value Preferred Equity Equity / Total Capitalization Beta Beta Plains All American Pipeline, L.P. $23.97 $17,416 $11,501 39.8% 0.97 0.66 Genesis Energy, L.P. 21.63 2,651 4,194 61.3% 1.09 0.52 Unlevered Offshore Shell Midstream Partners, L.P. 18.57 4,241 2,116 33.3% 0.81 0.60 Beta Median 39.8% 0.97 0.60 Historical MRP Supply-Side MRP Risk-free Rate 3 2.9% 2.9% Unlevered Beta 0.60 0.60 Debt and Preferred / Total Capitalization 39.8% 39.8% Adjusted Levered Equity Beta 0.88 0.88 Historical MRP (7.1%) WACC Sensitivities Cost of Market Risk Premium (“MRP”) 4 7.1% 6.0% Equity / WACC Small Company Risk Premium 5 2.5% 2.5% Unlevered Beta 0.30 0.40 0.50 0.60 0.70 Equity Cost of Capital 6 11.6% 10.7% on ed / r ti 30.0% 7.0% 7.6% 8.3% 8.9% 9.6% r za 35.0% 6.9% 7.5% 8.2% 8.8% 9.4% Pre-Tax Cost of Debt 7 6.1% 6.1% fe i e l 2 40.0% 6.8% 7.4% 8.1% 8.7% 9.3% After-Tax Cost of Debt 4.3% 4.3% Pr pita a 45.0% 6.7% 7.3% 8.0% 8.6% 9.2% and C 50.0% 6.7% 7.3% 7.9% 8.5% 9.1% l WACC 8.7% 8.2% a 55.0% 6.6% 7.2% 7.8% 8.3% 8.9% Debt Tot 60.0% 6.5% 7.1% 7.6% 8.2% 8.8% Supply-Side MRP (6.0%) WACC Sensitivities Unlevered Beta / 0.30 0.40 0.50 0.60 0.70 Preferred ion 30.0% 6.7% 7.3% 7.8% 8.4% 8.9% a t z Capitali 35.0% 6.6% 7.2% 7.7% 8.2% 8.8% 40.0% 6.5% 7.1% 7.6% 8.1% 8.7% nd 45.0% 6.5% 7.0% 7.5% 8.0% 8.6% a 50.0% 6.4% 6.9% 7.4% 7.9% 8.4% ebt Total 55.0% 6.3% 6.8% 7.3% 7.8% 8.3% D 60.0% 6.2% 6.7% 7.2% 7.7% 8.2% Source: Predicted raw betas from FactSet; Adjusted Equity Beta calculated as: (0.67) × Raw Beta + (0.33) × 1.0 1. Unlevered Beta calculated as: Adjusted Equity Beta × (E/(E + D × (1-T)) 2. Assumes unitholder effective tax rate of 29.6% (80.0% of 37.0% tax rate) 3. 20-year Treasury as of March 7, 2019 4. Source: Duff & Phelps 5. Low Cap (Decile 9) by Duff & Phelps with a market capitalization between $299.4 million and $656.8 million. Market capitalization for Delta House based on 100% interest in Delta House 6. Equity Cost of Capital calculated as: Risk-free rate + (Levered Equity Beta × Market Risk Premium) + Small Company Risk Premium 7. Pre-Tax Cost of Debt based on yield to worst for Offshore Pipeline peers’ Senior Unsecured Notes as of March 7, 2019 with an average maturity of August 30, 2026, extended to 20-years by addition of 25 bps premium for U.S. Treasury maturing March 7, 2038 versus U.S. Treasury maturing August 30, 2026 65

Preliminary Draft Subject to Change Weighted Average Cost of Capital Analysis Delta House ($ in millions, except per unit amounts) Unit/Share Price Market Equity Total Debt and Total Debt and Preferred Adjusted Unlevered 1,2 Partnership / Corporation 3/7/19 Value Preferred Equity Equity / Total Capitalization Beta Beta Plains All American Pipeline, L.P. $23.97 $17,416 $11,501 39.8% 0.97 0.66 Genesis Energy, L.P. 21.63 2,651 4,194 61.3% 1.09 0.52 Unlevered Delta House Shell Midstream Partners, L.P. 18.57 4,241 2,116 33.3% 0.81 0.60 Beta Median 39.8% 0.97 0.60 Historical MRP Supply-Side MRP Risk-free Rate 3 2.9% 2.9% Unlevered Beta 0.60 0.60 Debt and Preferred / Total Capitalization 39.8% 39.8% Adjusted Levered Equity Beta 0.88 0.88 Historical MRP (7.1%) WACC Sensitivities Cost of Market Risk Premium (“MRP”) 4 7.1% 6.0% Equity / WACC Small Company Risk Premium 5 2.5% 2.5% Unlevered Beta 0.30 0.40 0.50 0.60 0.70 Equity Cost of Capital 6 11.6% 10.7% on ed / r ti 30.0% 7.0% 7.6% 8.3% 8.9% 9.6% r za 35.0% 6.9% 7.5% 8.2% 8.8% 9.4% Pre-Tax Cost of Debt 7 6.1% 6.1% fe i e l 2 40.0% 6.8% 7.4% 8.1% 8.7% 9.3% After-Tax Cost of Debt 4.3% 4.3% Pr pita a 45.0% 6.7% 7.3% 8.0% 8.6% 9.2% and C 50.0% 6.7% 7.3% 7.9% 8.5% 9.1% l WACC 8.7% 8.2% a 55.0% 6.6% 7.2% 7.8% 8.3% 8.9% Debt Tot 60.0% 6.5% 7.1% 7.6% 8.2% 8.8% Supply-Side MRP (6.0%) WACC Sensitivities Unlevered Beta / 0.30 0.40 0.50 0.60 0.70 Preferred ion 30.0% 6.7% 7.3% 7.8% 8.4% 8.9% a t z Capitali 35.0% 6.6% 7.2% 7.7% 8.2% 8.8% 40.0% 6.5% 7.1% 7.6% 8.1% 8.7% nd 45.0% 6.5% 7.0% 7.5% 8.0% 8.6% a 50.0% 6.4% 6.9% 7.4% 7.9% 8.4% ebt Total 55.0% 6.3% 6.8% 7.3% 7.8% 8.3% D 60.0% 6.2% 6.7% 7.2% 7.7% 8.2% Source: Predicted raw betas from FactSet; Adjusted Equity Beta calculated as: (0.67) × Raw Beta + (0.33) × 1.0 1. Unlevered Beta calculated as: Adjusted Equity Beta × (E/(E + D × (1-T)) 2. Assumes unitholder effective tax rate of 29.6% (80.0% of 37.0% tax rate) 3. 20-year Treasury as of March 7, 2019 4. Source: Duff & Phelps 5. Low Cap (Decile 9) by Duff & Phelps with a market capitalization between $299.4 million and $656.8 million. Market capitalization for Delta House based on 100% interest in Delta House 6. Equity Cost of Capital calculated as: Risk-free rate + (Levered Equity Beta × Market Risk Premium) + Small Company Risk Premium 7. Pre-Tax Cost of Debt based on yield to worst for Offshore Pipeline peers’ Senior Unsecured Notes as of March 7, 2019 with an average maturity of August 30, 2026, extended to 20-years by addition of 25 bps premium for U.S. Treasury maturing March 7, 2038 versus U.S. Treasury maturing August 30, 2026 66 Preliminary Draft Subject to Change Weighted Average Cost of Capital Analysis Bakken Crude Oil Gathering ($ in millions, except per unit amounts) Unit/Share Price Market Equity Total Debt and Total Debt and Preferred Adjusted Unlevered 1,2 Partnership / Corporation 3/7/19 Value Preferred Equity Equity / Total Capitalization Beta Beta Delek Logistics Partners, LP $32.15 $801 $700 46.7% 0.79 0.49 Crude Oil Genesis Energy, L.P. 21.63 2,651 4,194 61.3% 1.09 0.52 Unlevered Gathering NGL Energy Partners LP 13.18 1,636 2,215 57.5% 1.09 0.56 Beta Plains All American Pipeline, L.P. 23.97 17,416 11,501 39.8% 0.97 0.66 Median 52.1% 1.03 0.54 Historical MRP Supply-Side MRP Risk-free Rate 3 2.9% 2.9% Unlevered Beta 0.54 0.54 Debt and Preferred / Total Capitalization 52.1% 52.1% Adjusted Levered Equity Beta 0.95 0.95 Cost of Market Risk Premium (“MRP”) 4 7.1% 6.0% Historical MRP (7.1%) WACC Sensitivities Equity / WACC Small Company Risk Premium 5 11.4% 11.4% Unlevered Beta 6 Equity Cost of Capital 20.9% 20.0% 0.30 0.40 0.50 0.60 0.70 7 ed / ti on 30.0% 13.4% 14.0% 14.6% 15.3% 15.9% Pre-Tax Cost of Debt 6.9% 6.9% r r a 35.0% 12.9% 13.5% 14.1% 14.8% 15.4% 2 fe e l iz After-Tax Cost of Debt 4.9% 4.9% 40.0% 12.4% 13.0% 13.6% 14.2% 14.8% Pr pita a 45.0% 11.9% 12.5% 13.1% 13.7% 14.3% WACC 12.6% 12.1% nd C al 50.0% 11.4% 12.0% 12.6% 13.2% 13.8% a 55.0% 10.9% 11.4% 12.0% 12.6% 13.2% Debt Tot 60.0% 10.4% 10.9% 11.5% 12.1% 12.7% Supply-Side MRP (6.0%) WACC Sensitivities Unlevered Beta / 0.30 0.40 0.50 0.60 0.70 d e ation 30.0% 13.1% 13.6% 14.2% 14.7% 15.3% referr liz 35.0% 12.6% 13.1% 13.7% 14.2% 14.7% P 40.0% 12.1% 12.6% 13.1% 13.7% 14.2% Capita 45.0% 11.6% 12.1% 12.6% 13.2% 13.7% and 50.0% 11.1% 11.6% 12.1% 12.6% 13.1% al 55.0% 10.6% 11.1% 11.6% 12.1% 12.6% Debt Tot 60.0% 10.1% 10.6% 11.1% 11.6% 12.1% Source: Predicted raw betas from FactSet; Adjusted Equity Beta calculated as: (0.67) × Raw Beta + (0.33) × 1.0 1. Unlevered Beta calculated as: Adjusted Equity Beta × (E/(E + D × (1-T)) 2. Assumes unitholder effective tax rate of 29.6% (80.0% of 37.0% tax rate) 3. 20-year Treasury as of March 7, 2019 4. Source: Duff & Phelps 5. Low Cap (Decile 10z) by Duff & Phelps with a market capitalization between $2.5 million and $87.6 million 6. Equity Cost of Capital calculated as: Risk-free rate + (Levered Equity Beta × Market Risk Premium) + Small Company Risk Premium 7. Pre-Tax Cost of Debt based on yield to worst for Crude Oil Gathering peers’ Senior Unsecured Notes as of March 7, 2019 with an average maturity of December 18, 2025, extended to 20-years by addition of 27 bps premium for U.S. Treasury maturing March 7, 2038 versus U.S. Treasury maturing December 18, 2025 67

Preliminary Draft Subject to Change Weighted Average Cost of Capital Analysis Silver Dollar Pipeline ($ in millions, except per unit amounts) Unit/Share Price Market Equity Total Debt and Total Debt and Preferred Adjusted Unlevered Partnership / Corporation 3/7/19 Value Preferred Equity Equity / Total Capitalization Beta Beta 1,2 Delek Logistics Partners, LP $32.15 $801 $700 46.7% 0.79 0.49 Crude Oil Genesis Energy, L.P. 21.63 2,651 4,194 61.3% 1.09 0.52 Unlevered Gathering NGL Energy Partners LP 13.18 1,636 2,215 57.5% 1.09 0.56 Beta Plains All American Pipeline, L.P. 23.97 17,416 11,501 39.8% 0.97 0.66 Median 52.1% 1.03 0.54 Historical MRP Supply-Side MRP Risk-free Rate 3 2.9% 2.9% Unlevered Beta 0.54 0.54 Debt and Preferred / Total Capitalization 52.1% 52.1% Adjusted Levered Equity Beta 0.95 0.95 Cost of Market Risk Premium (“MRP”) 4 7.1% 6.0% Historical MRP (7.1%) WACC Sensitivities Equity / WACC Small Company Risk Premium 5 7.0% 7.0% Unlevered Beta 6 Equity Cost of Capital 16.5% 15.6% 0.30 0.40 0.50 0.60 0.70 7 ed / ti on 30.0% 10.3% 10.9% 11.6% 12.2% 12.9% Pre-Tax Cost of Debt 6.9% 6.9% r r a 35.0% 10.0% 10.6% 11.3% 11.9% 12.5% 2 fe e l iz After-Tax Cost of Debt 4.9% 4.9% 40.0% 9.7% 10.3% 11.0% 11.6% 12.2% Pr pita a 45.0% 9.4% 10.0% 10.7% 11.3% 11.9% WACC 10.5% 10.0% nd C al 50.0% 9.2% 9.8% 10.4% 11.0% 11.6% a 55.0% 8.9% 9.5% 10.1% 10.6% 11.2% Debt Tot 60.0% 8.6% 9.2% 9.8% 10.3% 10.9% Supply-Side MRP (6.0%) WACC Sensitivities Unlevered Beta / 0.30 0.40 0.50 0.60 0.70 d e ation 30.0% 10.0% 10.5% 11.1% 11.6% 12.2% referr liz 35.0% 9.7% 10.3% 10.8% 11.3% 11.9% P 40.0% 9.4% 10.0% 10.5% 11.0% 11.6% Capita 45.0% 9.2% 9.7% 10.2% 10.7% 11.3% and 50.0% 8.9% 9.4% 9.9% 10.4% 10.9% al 55.0% 8.6% 9.1% 9.6% 10.1% 10.6% Debt Tot 60.0% 8.3% 8.8% 9.3% 9.8% 10.3% Source: Predicted raw betas from FactSet; Adjusted Equity Beta calculated as: (0.67) × Raw Beta + (0.33) × 1.0 1. Unlevered Beta calculated as: Adjusted Equity Beta × (E/(E + D × (1-T)) 2. Assumes unitholder effective tax rate of 29.6% (80.0% of 37.0% tax rate) 3. 20-year Treasury as of March 7, 2019 4. Source: Duff & Phelps 5. Low Cap (Decile 10y) by Duff & Phelps with a market capitalization between $87.6 million and $166.3 million 6. Equity Cost of Capital calculated as: Risk-free rate + (Levered Equity Beta × Market Risk Premium) + Small Company Risk Premium 7. Pre-Tax Cost of Debt based on yield to worst for Crude Oil Gathering peers’ Senior Unsecured Notes as of March 7, 2019 with an average maturity of December 18, 2025, extended to 20-years by addition of 27 bps premium for U.S. Treasury maturing March 7, 2038 versus U.S. Treasury maturing December 18, 2025 68 Preliminary Draft Subject to Change Weighted Average Cost of Capital Analysis Crude Oil Storage ($ in millions, except per unit amounts) Unit/Share Price Market Equity Total Debt and Total Debt and Preferred Adjusted Unlevered 1,2 Partnership / Corporation 3/7/19 Value Preferred Equity Equity / Total Capitalization Beta Beta Blueknight Energy Partners, L.P. $1.14 $47 $526 91.8% 1.01 0.11 Global Partners LP 19.10 654 1,138 63.5% 0.92 0.41 Crude Oil Sprague Resources LP 15.30 348 616 63.9% 0.87 0.39 Unlevered Storage USD Partners LP 11.10 301 206 40.6% 0.67 0.45 Beta Median 63.7% 0.90 0.40 Historical MRP Supply-Side MRP Risk-free Rate 3 2.9% 2.9% Unlevered Beta 0.40 0.40 Debt and Preferred / Total Capitalization 63.7% 63.7% Adjusted Levered Equity Beta 0.90 0.90 Cost of Market Risk Premium (“MRP”) 4 7.1% 6.0% Equity / WACC 5 Historical MRP (7.1%) WACC Sensitivities Small Company Risk Premium 11.4% 11.4% Equity Cost of Capital 6 20.6% 19.7% Unlevered Beta 0.10 0.20 0.30 0.40 0.50 7 ed / on 30.0% 12.2% 12.8% 13.5% 14.1% 14.7% Pre-Tax Cost of Debt 7.4% 7.4% ti r r a After-Tax Cost of Debt 2 5.2% 5.2% fe iz 35.0% 11.7% 12.3% 13.0% 13.6% 14.2% e l 40.0% 11.2% 11.9% 12.5% 13.1% 13.7% Pr pita WACC 10.8% 10.4% 60.0% 9.4% 10.0% 10.5% 11.1% 11.7% nd C a al 65.0% 8.9% 9.5% 10.1% 10.6% 11.2% a 70.0% 8.5% 9.0% 9.6% 10.1% 10.7% Debt Tot 75.0% 8.0% 8.5% 9.1% 9.6% 10.2% Supply-Side MRP (6.0%) WACC Sensitivities Unlevered Beta / 0.10 0.20 0.30 0.40 0.50 d e ation 30.0% 12.1% 12.6% 13.2% 13.7% 14.3% referr liz 35.0% 11.6% 12.2% 12.7% 13.2% 13.8% P 40.0% 11.1% 11.7% 12.2% 12.7% 13.3% Capita 60.0% 9.3% 9.8% 10.3% 10.8% 11.3% and 65.0% 8.8% 9.3% 9.8% 10.3% 10.8% al 70.0% 8.4% 8.9% 9.3% 9.8% 10.3% Debt Tot 75.0% 7.9% 8.4% 8.9% 9.3% 9.8% Source: Predicted raw betas from FactSet; Adjusted Equity Beta calculated as: (0.67) × Raw Beta + (0.33) × 1.0 1. Unlevered Beta calculated as: Adjusted Equity Beta × (E/(E + D × (1-T)) 2. Assumes unitholder effective tax rate of 29.6% (80.0% of 37.0% tax rate) 3. 20-year Treasury as of March 7, 2019 4. Source: Duff & Phelps 5. Low Cap (Decile 10z) by Duff & Phelps with a market capitalization between $2.5 million and $87.6 million 6. Equity Cost of Capital calculated as: Risk-free rate + (Levered Equity Beta × Market Risk Premium) + Small Company Risk Premium 7. Pre-Tax Cost of Debt based on yield to worst for Global Partners LP’s Senior Unsecured Notes maturing June 15, 2023 as of March 7, 2019, extended to 20-years by addition of 35 bps premium for U.S. Treasury maturing March 7, 2038 versus U.S. Treasury maturing June 15, 2023 69

Preliminary Draft Subject to Change Weighted Average Cost of Capital Analysis NGL Transportation ($ in millions, except per unit / share amounts) Unit/Share Price Market Equity Total Debt and Total Debt and Preferred Adjusted Unlevered 1,2 Partnership / Corporation 3/7/19 Value Preferred Equity Equity / Total Capitalization Beta Beta Enterprise Products Partners L.P. $28.22 $61,657 $26,178 29.8% 0.87 0.67 NGL ONEOK, Inc. 65.89 27,121 9,381 25.7% 0.96 0.75 Unlevered Transportation Phillips 66 Partners LP 50.68 6,418 3,794 37.2% 0.79 0.56 Beta Targa Resources Corp. 40.09 9,307 8,552 47.9% 0.97 0.56 Median 33.5% 0.91 0.62 Historical MRP Supply-Side MRP Risk-free Rate 3 2.9% 2.9% Unlevered Beta 0.62 0.62 Debt and Preferred / Total Capitalization 33.5% 33.5% Adjusted Levered Equity Beta 0.83 0.83 Cost of 4 Historical MRP (7.1%) WACC Sensitivities Market Risk Premium (“MRP”) 7.1% 6.0% Equity / WACC Small Company Risk Premium 5 2.5% 2.5% Unlevered Beta 6 11.3% 10.4% 0.30 0.40 0.50 0.60 0.70 Equity Cost of Capital on ed / r ti 30.0% 6.7% 7.3% 8.0% 8.6% 9.2% r a Pre-Tax Cost of Debt 7 4.6% 4.6% fe iz 35.0% 6.5% 7.2% 7.8% 8.4% 9.1% e l 40.0% 6.4% 7.0% 7.6% 8.3% 8.9% After-Tax Cost of Debt 2 3.3% 3.3% Pr pita nd a 45.0% 6.3% 6.9% 7.5% 8.1% 8.7% C 50.0% 6.1% 6.7% 7.3% 7.9% 8.5% a l WACC 8.6% 8.0% a 55.0% 6.0% 6.6% 7.2% 7.8% 8.3% Debt Tot 60.0% 5.8% 6.4% 7.0% 7.6% 8.2% Supply-Side MRP (6.0%) WACC Sensitivities Unlevered Beta / 0.30 0.40 0.50 0.60 0.70 d e ation 30.0% 6.4% 6.9% 7.5% 8.0% 8.6% referr liz 35.0% 6.2% 6.8% 7.3% 7.9% 8.4% P 40.0% 6.1% 6.6% 7.2% 7.7% 8.2% Capita 45.0% 6.0% 6.5% 7.0% 7.6% 8.1% and 50.0% 5.9% 6.4% 6.9% 7.4% 7.9% al 55.0% 5.7% 6.2% 6.7% 7.2% 7.7% Debt Tot 60.0% 5.6% 6.1% 6.6% 7.1% 7.6% Source: Predicted raw betas from FactSet; Adjusted Equity Beta calculated as: (0.67) × Raw Beta + (0.33) × 1.0 1. Unlevered Beta calculated as: Adjusted Equity Beta × (E/(E + D × (1-T)) 2. Assumes unitholder effective tax rate of 29.6% (80.0% of 37.0% tax rate) for Partnerships and tax rate of 21.0% for Corporations 3. 20-year Treasury as of March 7, 2019 4. Source: Duff & Phelps 5. Low Cap (Decile 9) by Duff & Phelps with a market capitalization between $299.4 million and $656.8 million. Market capitalization based on 100% interest in Wilprise, Tri-States and Cayenne. 6. Equity Cost of Capital calculated as: Risk-free rate + (Levered Equity Beta × Market Risk Premium) + Small Company Risk Premium 7. Pre-Tax Cost of Debt based on yield to worst for NGL Transportation peers’ Senior Unsecured Notes as of March 7, 2019 with an average maturity of April 16, 2032, extended to 20-years by addition of 11 bps premium for U.S. Treasury maturing March 7, 2038 versus U.S. Treasury maturing April 16, 2032 70 Preliminary Draft Subject to Change B. Detailed Segment Financial Projections

Preliminary Draft Subject to Change Detailed Segment Financial Projections Gathering & Processing ($ in millions) Volume (MMcfd) Asset EBITDA 385.6 $68.6 $71.8 $73.1 361.5 $59.7 334.5 299.4 247.0 $38.6 164.9 189.0 $24.5 $11.0 2017A 2018A 2019E 2020E 2021E 2022E 2023E 2017A 2018A 2019E 2020E 2021E 2022E 2023E Total Capital Expenditures1 Free Cash Flow $106.7 $42.7 $45.1 $36.2 $1.7 $58.0 ($4.1) ($10.6) $35.1 $32.4 $29.1 $28.1 $15.1 2017A 2018A 2019E 2020E 2021E 2022E 2023E ($68.2) 2017A 2018A 2019E 2020E 2021E 2022E 2023E Source: AMID management 1. 2019E capital expenditures include Longview Expansion, acquisition of interest in the Pascagoula Plant and well connects to Lavaca and Yellow Rose; investment in Baton Rouge Fractionator has been removed per AMID management 71 Preliminary Draft Subject to Change Detailed Segment Financial Projections Natural Gas Gathering and Processing ($ in millions) AMID Financial Projections For the Twelve Months Ended December 31, 2018A – 2023E 2017A 2018A 2019E 2020E 2021E 2022E 2023E CAGR Volumes (MMcfd) East Texas 43.1 42.1 42.7 43.0 43.5 44.0 44.4 Lavaca 106.3 130.3 183.5 229.2 260.1 286.5 310.5 Chatom / Glade Crossing 10.8 9.7 12.8 14.0 13.9 13.7 13.4 Permian 4.7 6.9 8.0 13.2 17.0 17.4 17.3 Total Volumes 164.9 189.0 247.0 299.4 334.5 361.5 385.6 15.3% Gross Margin East Texas $22.0 $21.5 $19.8 $20.4 $19.6 $19.4 $19.4 Lavaca 14.1 17.7 28.3 37.4 42.7 47.0 50.7 Chatom / Glade Crossing 3.3 7.7 9.3 10.5 9.5 9.4 8.5 Permian 3.3 4.7 7.2 9.5 11.1 11.3 11.2 Longview Plant Expansion -- -- -- 6.8 11.6 11.6 11.6 Pascagoula Gas Plant -- -- 6.7 9.3 8.9 8.3 7.1 Gross Margin $42.7 $51.6 $71.2 $93.8 $103.4 $106.9 $108.6 16.0% Operating Expenses East Texas ($12.5) ($11.1) ($11.8) ($11.9) ($11.9) ($11.9) ($11.9) Lavaca (7.6) (7.0) (9.3) (10.0) (10.4) (10.6) (10.9) Chatom / Glade Crossing (7.7) (7.4) (6.8) (7.0) (7.0) (7.0) (7.1) Permian (3.1) (2.7) (2.7) (3.0) (3.2) (3.3) (3.3) Pascagoula Gas Plant -- -- (1.9) (2.2) (2.3) (2.3) (2.3) Other (0.8) 1.0 (0.1) (0.0) (0.0) (0.0) (0.0) Operating Expenses ($31.7) ($27.1) ($32.7) ($34.1) ($34.8) ($35.2) ($35.5) 5.5% EBITDA $11.0 $24.5 $38.6 $59.7 $68.6 $71.8 $73.1 Maintenance Capital Expenditures (1.9) (5.4) (2.7) (3.0) (3.0) (3.0) (3.0) Growth Capital Expenditures (13.2) (29.7) (104.1) (55.0) (29.4) (26.1) (25.1) Free Cash Flow ($4.1) ($10.6) ($68.2) $1.7 $36.2 $42.7 $45.1 NA Source: AMID management Note: Burns Point plant capacity excluded from total due to maintenance issues shutting down plant operations in December 2017 72

Preliminary Draft Subject to Change Detailed Segment Financial Projections Natural Gas Transportation ($ in millions) Volume (BBtud) Asset EBITDA 2018A to 2019E EBITDA decline driven by interruptible volume and non-recurring marketing fuel gains in 2018A 1.26 $27.9 1.24 $25.2 $26.0 $26.0 1.20 1.20 1.20 $22.3 $23.5 1.17 1.18 $18.3 2017A 2018A 2019E 2020E 2021E 2022E 2023E 2017A 2018A 2019E 2020E 2021E 2022E 2023E Total Capital Expenditures Free Cash Flow $23.0 $22.5 $22.5 $35.4 $20.8 $18.9 $10.6 $11.7 $4.9 $4.6 $4.4 $3.5 $3.5 ($52.5) 2017A 2018A 2019E 2020E 2021E 2022E 2023E 2017A 2018A 2019E 2020E 2021E 2022E 2023E Source: AMID management 73 Preliminary Draft Subject to Change Detailed Segment Financial Projections Natural Gas Transportation ($ in millions) AMID Financial Projections For the Twelve Months Ending December 31, 2018A – 2023E 2017A 2018A 2019E 2020E 2021E 2022E 2023E CAGR Volumes (MMBtu/d) Alatenn Pipelines 307,240 309,785 336,011 362,781 388,340 388,340 388,340 TransUnion 470,000 470,029 470,000 470,000 470,000 470,000 470,000 Magnolia 95,110 77,255 54,188 49,256 49,256 49,256 49,256 Midla / MLGT 367,235 402,775 312,348 295,516 295,170 295,170 295,170 Total Volumes 1,239,585 1,259,843 1,172,546 1,177,553 1,202,766 1,202,766 1,202,766 (0.9%) Gross Margin Alatenn Pipelines $9.3 $9.6 $9.5 $9.5 $10.1 $10.1 $10.1 TransUnion 1.2 6.3 6.2 6.2 6.2 6.2 6.2 Magnolia 6.0 5.9 4.1 3.9 3.2 3.2 3.3 Midla / MLGT 7.8 8.0 8.5 9.5 11.7 13.1 13.1 Fuel Gain / Other 0.0 6.3 1.5 2.1 1.6 1.0 1.0 Total Gross Margin $24.3 $36.1 $29.8 $31.1 $32.8 $33.7 $33.7 (1.4%) Operating Expenses Alatenn Pipelines ($1.5) ($2.9) ($2.9) ($3.1) ($3.1) ($3.1) ($3.1) TransUnion (0.1) (0.5) (0.6) (0.6) (0.6) (0.6) (0.6) Magnolia (0.8) (1.7) (1.1) (1.1) (1.1) (1.1) (1.1) Midla / MLGT (3.6) (3.1) (2.9) (2.9) (2.9) (2.9) (2.9) Operating Expenses ($6.0) ($8.3) ($7.5) ($7.6) ($7.6) ($7.7) ($7.7) (1.5%) EBITDA Alatenn Pipelines $7.7 $6.6 $6.6 $6.4 $7.0 $7.0 $7.0 TransUnion 1.1 5.9 5.6 5.6 5.6 5.6 5.6 Magnolia 5.2 4.2 3.0 2.8 2.2 2.2 2.2 Midla / MLGT 4.2 4.9 5.7 6.6 8.8 10.2 10.2 Fuel Gain / Other 0.0 6.3 1.5 2.1 1.6 1.0 1.0 EBITDA $18.3 $27.9 $22.3 $23.5 $25.2 $26.0 $26.0 (1.3%) Maintenance Capital Expenditures (1.9) (1.2) (3.4) (3.5) (3.5) (3.5) (3.5) Growth Capital Expenditures (33.5) (3.7) (8.4) (1.1) (0.9) -- -- Free Cash Flow ($17.1) $23.0 $10.6 $18.9 $20.8 $22.5 $22.5 (0.4%) Source: AMID management 74

Preliminary Draft Subject to Change Detailed Segment Financial Projections Offshore Pipelines (excluding Delta House) ($ in millions) Volume (MMBtud) Asset EBITDA1 1.74 1.80 1.69 1.61 1.49 1.46 $81.6 $78.4 $75.2 $70.7 $65.1 $57.9 2018A 2019E 2020E 2021E 2022E 2023E 2018A 2019E 2020E 2021E 2022E 2023E Total Capital Expenditures1 Free Cash Flow1 2 $24.7 $79.6 $75.5 $74.5 $66.1 $60.9 $53.9 $11.3 $4.0 $4.0 $4.0 $4.0 2018A 2019E 2020E 2021E 2022E 2023E 2018A 2019E 2020E 2021E 2022E 2023E Source: AMID management 1. Pro rata for AMID’s 66.7% interest in Okeanos and Destin 2. Includes distributions from Okeanos and Destin based on preceding quarter’s free cash flow 75 Preliminary Draft Subject to Change Detailed Segment Financial Projections Offshore Pipelines excl. Delta House ($ in millions) AMID Financial Projections For the Twelve Months Ending December 31, 2018A – 2023E 2018A 2019E 2020E 2021E 2022E 2023E CAGR Gas Volumes (MMBtu/d) Destin-Okeanos (66.7% Ownership) 1,110,014 1,253,912 1,313,448 1,222,610 1,180,244 1,075,843 High Point Pipelines 319,319 348,275 345,326 338,439 310,503 281,825 Panther Pipelines 61,049 140,469 141,617 127,575 115,096 103,981 Total Gas Volumes 1,490,382 1,742,657 1,800,392 1,688,624 1,605,843 1,461,648 (0.4%) Crude Oil Volumes (MBpd) AmPan Pipelines 9.7 8.5 7.7 6.9 6.2 5.6 Main Pass Oil Gathering 26.6 30.4 28.0 25.8 23.7 21.8 Total Oil Volumes 36.4 38.9 35.7 32.7 29.9 27.4 (5.5%) Gross Margin Destin-Okeanos (100% Gross) $82.9 $76.5 $80.3 $71.3 $66.4 $59.2 Other 64.2 67.8 68.6 66.9 64.5 62.2 Total Gross Margin (100% Consolidated) $147.1 $144.4 $148.9 $138.2 $130.9 $121.3 (3.8%) Operating Expenses Destin-Okeanos (100% Gross) ($12.5) ($14.4) ($14.4) ($14.4) ($14.4) ($14.4) Other (29.6) (34.1) (34.1) (34.1) (34.1) (34.1) Operating Expenses (100% Consolidated) ($42.1) ($48.5) ($48.5) ($48.5) ($48.5) ($48.5) 2.9% EBITDA Destin-Okeanos (100% Gross) $70.5 $62.1 $65.9 $56.8 $51.9 $44.8 Other 34.6 33.7 34.5 32.8 30.4 28.0 EBITDA (100% Consolidated) $105.1 $95.9 $100.4 $89.6 $82.4 $72.8 (7.1%) Maintenance Capital Expenditures Destin-Okeanos (100% Gross) $-- $-- $-- $-- $-- $-- Other (1.9) (6.9) (4.0) (4.0) (4.0) (4.0) Maintenance Capital Expenditures (100% Consolidated) ($1.9) ($6.9) ($4.0) ($4.0) ($4.0) ($4.0) 15.6% Growth Capital Expenditures Destin-Okeanos (100% Gross) $-- $-- $-- $-- $-- $-- Other (22.8) (4.3) -- -- -- -- Growth Capital Expenditures (100% Consolidated) ($22.8) ($4.3) $-- $-- $-- $-- NA Free Cash Flow Destin-Okeanos (66.7% Net) $47.0 $41.4 $44.0 $37.9 $34.6 $29.9 Other 9.9 22.5 30.5 28.8 26.4 24.0 Free Cash Flow (Net to AMID) $56.9 $63.9 $74.4 $66.7 $61.1 $53.9 (1.1%) Source: AMID management 76

Preliminary Draft Subject to Change Detailed Segment Financial Projections Delta House ($ in millions) Volume (MBoed) Asset EBITDA (35.65%) 1 $89.3 $85.9 118.7 118.1 106.7 110.9 104.6 102.3 $58.3 $56.4 81.0 72.5 $49.6 $43.5 65.5 $34.9 $27.4 $25.5 2017A 2018A 2019E 2020E 2021E 2022E 2023E 2024E 2025E 2017A 2018A 2019E 2020E 2021E 2022E 2023E 2024E 2025E Class A Distributions2 (35.65% interest) Production significantly curtailed through $86.7 2Q 2018 due to remedial work on third party upstream infrastructure $63.5 $47.7 $43.7 $44.3 $40.2 $34.4 $27.9 $24.3 3 2017A 2018A 2019E 2020E 2021E 2022E 2023E 2024E 2025E Source: AMID management 1. Inclusive of deferred revenue 2. Includes change in working capital and deferred revenue (adjusted calculation per AMID management which impacted free cash flow forecast but did not affect cash distribution forecast flowing through valuation) 3. Actual 2018A distribution slightly higher than projected 77 Preliminary Draft Subject to Change Detailed Segment Financial Projections Delta House ($ in millions) AMID Financial Projections For the Twelve Months Ending December 31, 2018A – 2025E 2018A 2019E 2020E 2021E 2022E 2023E 2024E 2025E CAGR Gas Transportation (MMcfd) 86.1 175.5 179.9 181.1 178.1 150.9 116.4 112.7 Oil Transportation (MBpd) 51.1 77.4 88.7 87.9 81.2 77.2 61.6 53.7 FPS Throughput (MBoed) 65.5 106.7 118.7 118.1 110.9 102.3 81.0 72.5 1.5% Processing Revenue $103.1 $170.4 $176.6 $159.8 $139.2 $124.4 $94.6 $90.6 Gas Transportation Revenue 18.4 33.2 33.3 34.4 32.7 26.8 20.5 19.9 Oil Transportation Revenue 21.6 30.5 33.7 32.2 28.8 25.4 19.8 17.6 Other Revenue 0.1 -- -- -- -- -- -- -- Gross Margin $143.2 $234.1 $243.6 $226.4 $200.8 $176.7 $134.9 $128.1 (1.6%) Operating Expenses (1.4) (0.9) (0.9) (0.9) (0.9) (0.9) (0.9) (1.0) EBITDA $141.9 $233.3 $242.7 $225.5 $199.8 $175.8 $133.9 $127.2 (1.6%) Less: Change in Deferred Revenue 21.6 16.8 (84.7) (86.7) (78.0) (78.0) (57.2) (55.6) Less: Change in Working Capital (13.3) (6.1) 22.0 (0.8) 6.2 2.4 3.9 (1.2) Less: Interest Expense (0.9) -- -- -- -- -- -- -- Levered Free Cash Flow $149.2 $244.0 $180.0 $138.1 $128.1 $100.2 $80.6 $70.3 (10.2%) Less: Term Loan Amortization (39.8) -- -- -- -- -- -- -- Less: Class B Carry -- -- (1.2) (3.5) (3.3) (3.0) (2.4) (2.2) Class A Cash Flows (100%) $109.4 $244.0 $178.8 $134.6 $124.8 $97.2 $78.2 $68.1 Class A Cash Flows (35.65%) $39.0 $87.0 $63.7 $48.0 $44.5 $34.6 $27.9 $24.3 Less: AMID Level Delta House Insurance Expense (0.2) (0.2) (0.2) (0.2) (0.2) (0.2) -- -- Delta House Net Distributions to AMID $38.8 $86.7 $63.5 $47.7 $44.3 $34.4 $27.9 $24.3 Source: AMID management 78

Preliminary Draft Subject to Change Detailed Segment Financial Projections Trucking (South Texas + Liquids) ($ in millions) Volume (MBoed) Asset EBITDA 19.2 16.0 16.4 16.4 16.4 16.4 14.7 ($1.0) ($1.0) ($1.0) ($1.0) ($1.1) ($1.1) ($1.9) 2017A 2018A 2019E 2020E 2021E 2022E 2023E 2017A 2018A 2019E 2020E 2021E 2022E 2023E Free Cash Flow ($1.1) ($1.0) ($1.0) ($1.0) ($1.0) ($1.1) ($1.9) 2017A 2018A 2019E 2020E 2021E 2022E 2023E Source: AMID management Note: 2017A, 2018A and January 2019E includes Texas Panhandle operations 79 Preliminary Draft Subject to Change Detailed Segment Financial Projections Trucking ($ in millions) AMID Financial Projections For the Twelve Months Ending December 31, 2018A – 2023E 2017A 2018A 2019E 2020E 2021E 2022E 2023E CAGR Volumes (MBpd) South Texas Crude Trucking 6.2 7.2 12.8 14.0 14.0 14.0 14.0 Texas Panhandle Crude Trucking 6.4 9.4 0.8 -- -- -- -- Liquids Trucking 2.1 2.6 2.4 2.4 2.4 2.4 2.4 Volumes 14.7 19.2 16.0 16.4 16.4 16.4 16.4 (3.2%) Gross Margin South Texas Crude Trucking $0.9 $0.8 $1.0 $0.9 $0.9 $0.9 $0.9 Texas Panhandle Crude Trucking 1.6 0.5 (0.1) -- -- -- -- Liquids Trucking 1.4 0.8 1.1 1.0 1.0 1.0 1.0 Gross Margin $3.9 $2.1 $2.0 $1.9 $1.9 $1.9 $1.9 (2.2%) Operating Expenses South Texas Crude Trucking ($1.7) ($1.3) ($1.4) ($1.4) ($1.4) ($1.4) ($1.4) Texas Panhandle Crude Trucking (1.2) (1.3) (0.2) -- -- -- -- Liquids Trucking (2.1) (1.4) (1.5) (1.5) (1.5) (1.5) (1.5) Operating Expenses ($5.0) ($4.0) ($3.1) ($2.9) ($2.9) ($2.9) ($2.9) (6.1%) EBITDA ($1.1) ($1.9) ($1.1) ($1.0) ($1.0) ($1.0) ($1.0) NA Maintenance Capital Expenditures South Texas Crude Trucking $-- $-- $-- $-- $-- $-- $-- Texas Panhandle Crude Trucking -- -- -- -- -- -- -- Liquids Trucking -- -- -- -- -- -- -- Total Maintenance Capital Expenditures $-- $-- $-- $-- $-- $-- $-- NA Growth Capital Expenditures South Texas Crude Trucking $-- $-- $-- $-- $-- $-- $-- Texas Panhandle Crude Trucking -- -- -- -- -- -- -- Liquids Trucking -- -- -- -- -- -- -- Total Growth Capital Expenditures $-- $-- $-- $-- $-- $-- $-- NA Free Cash Flow ($1.1) ($1.9) ($1.1) ($1.0) ($1.0) ($1.0) ($1.0) NA Source: AMID management 80

Preliminary Draft Subject to Change Detailed Segment Financial Projections Bakken Crude Gathering & Marketing ($ in millions) Volume (MBoed) Asset EBITDA 16.3 14.9 $4.4 12.5 12.5 $3.8 $3.6 6.8 6.2 10.4 9.2 $2.9 4.0 5.2 7.3 $2.1 4.3 3.5 2.9 $1.3 9.5 8.7 $1.0 8.5 7.3 6.1 4.4 5.6 2017A 2018A 2019E 2020E 2021E 2022E 2023E 2017A 2018A 2019E 2020E 2021E 2022E 2023E Volumes Gathered (MBpd) Volumes Trucked (MBpd) Total Capital Expenditures Free Cash Flow $2.7 $4.3 $3.7 $3.5 $2.8 $2.0 $1.2 $0.1 $0.1 $0.1 $0.1 $0.1 $0.1 ($1.7) 2017A 2018A 2019E 2020E 2021E 2022E 2023E 2017A 2018A 2019E 2020E 2021E 2022E 2023E Source: AMID management 81 Preliminary Draft Subject to Change Detailed Segment Financial Projections Bakken Crude Oil Gathering ($ in millions) AMID Financial Projections For the Twelve Month Ending December 31, 2018A – 2023E 2017A 2018A 2019E 2020E 2021E 2022E 2023E CAGR Transportation Volume (MBpd) 4.4 5.6 8.5 9.5 8.7 7.3 6.1 1.5% Trucking Volume (MBpd) 2.9 3.5 4.0 6.8 6.2 5.2 4.3 4.1% Gross Margin $3.1 $3.7 $7.2 $9.5 $8.7 $7.3 $6.1 Operating Expenses (2.1) (1.8) (3.6) (5.1) (4.9) (4.4) (4.0) Marketing Margin (0.3) (0.6) (0.0) -- -- 0.0 (0.0) EBITDA $0.7 $1.3 $3.6 $4.4 $3.8 $2.9 $2.1 9.4% Maintenance Capital Expenditures (0.2) (0.1) (0.1) (0.1) (0.1) (0.1) (0.1) Growth Capital Expenditures (2.5) (1.1) -- -- -- -- -- Free Cash Flow ($1.7) $0.1 $3.5 $4.3 $3.7 $2.8 $2.0 86.8% Source: AMID management 82

Preliminary Draft Subject to Change Detailed Segment Financial Projections Silver Dollar (including West Texas Trucking and Marketing) ($ in millions) Volume (MBoed) Asset EBITDA 99.1 95.7 90.8 82.4 $22.7 21.2 $22.0 $22.1 21.2 21.2 $19.3 21.2 $16.8 56.1 $16.1 15.5 32.5 $10.0 29.5 77.9 1.7 69.7 74.6 61.2 40.5 29.5 30.8 2017A 2018A 2019E 2020E 2021E 2022E 2023E 2017A 2018A 2019E 2020E 2021E 2022E 2023E Volumes Gathered (MBpd) Volumes Trucked (MBpd) Total Capital Expenditures Free Cash Flow $22.3 $14.1 $14.8 $21.5 $21.7 $13.1 $10.6 $6.2 $6.2 $2.0 $0.5 $0.4 $0.4 ($4.8) 2017A 2018A 2019E 2020E 2021E 2022E 2023E 2017A 2018A 2019E 2020E 2021E 2022E 2023E Source: AMID management 83 Preliminary Draft Subject to Change Detailed Segment Financial Projections Silver Dollar Pipeline ($ in millions) AMID Financial Projections For the Twelve Months Ending December 31, 2018A – 2023E 2017A 2018A 2019E 2020E 2021E 2022E 2023E CAGR Silver Dollar Volume (MBpd) 29.5 30.8 40.5 61.2 69.7 74.6 77.9 West Texas Marketing Volume (MBpd) 17.6 -- 26.3 40.2 45.5 49.0 51.2 West Texas Trucking (MBpd) 0.0 1.7 15.5 21.2 21.2 21.2 21.2 Gross Margin Silver Dollar ($0.3) $13.2 $13.1 $19.9 $22.5 $22.3 $22.9 West Texas Marketing and Trucking 19.2 7.3 1.9 4.7 5.0 5.2 5.3 Gross Margin $18.9 $20.5 $15.0 $24.7 $27.5 $27.5 $28.2 6.6% Operating Expenses Silver Dollar $-- ($3.0) ($3.2) ($3.6) ($3.6) ($3.7) ($3.7) West Texas Marketing and Trucking (2.1) (1.4) (1.8) (1.8) (1.8) (1.8) (1.8) Operating Expenses ($2.1) ($4.4) ($5.0) ($5.4) ($5.4) ($5.4) ($5.5) 4.4% EBITDA $16.8 $16.1 $10.0 $19.3 $22.0 $22.1 $22.7 7.1% Maintenance Capital Expenditures Silver Dollar $-- $-- ($0.4) ($0.5) ($0.5) ($0.4) ($0.4) West Texas Marketing -- -- -- -- -- -- -- Total Maintenance Capital Expenditures $-- $-- ($0.4) ($0.5) ($0.5) ($0.4) ($0.4) NA Growth Capital Expenditures Silver Dollar ($6.2) ($14.1) ($14.3) ($12.6) $-- $-- $-- West Texas Marketing -- -- -- -- -- -- -- Total Growth Capital Expenditures ($6.2) ($14.1) ($14.3) ($12.6) $-- $-- $-- NA Free Cash Flow $10.6 $2.0 ($4.8) $6.2 $21.5 $21.7 $22.3 NA Source: AMID management 84

Preliminary Draft Subject to Change Detailed Segment Financial Projections Cushing Terminal ($ in millions, except per unit amounts) Available Storage Capacity (MMbls) Asset EBITDA / Rate per Barrel $10.0 $0.25 $8.0 $0.20 $0.20 3.0 3.0 3.0 3.0 $0.20 $0.20 M $8.0 $0.20 2.6 M) 2.4 ($ $6.0 T DA $4.5 $4.5 $4.5 $4.5 $0.15 Rate ($ $0.12 $0.10 1.3 EBI $4.0 / set Bbl) A s $0.10 $2.0 $1.0 $-- $0.05 2017A 2018A 2019E 2020E 2021E 2022E 2023E ($1.1) ($2.0) $--2017A 2018A 2019E 2020E 2021E 2022E 2023E Total Capital Expenditures Free Cash Flow $3.8 $3.4 $8.0 $4.5 $4.5 $4.5 $4.5 $1.0 $-- $-- $-- $-- $-- ($1.1) 2017A 2018A 2019E 2020E 2021E 2022E 2023E 2017A 2018A 2019E 2020E 2021E 2022E 2023E Source: AMID management 85 Preliminary Draft Subject to Change Detailed Segment Financial Projections Cushing Terminal ($ in millions) AMID Financial Projections For the Twelve Months Ending December 31, 2018A – 2023E 2017A 2018A 2019E 2020E 2021E 2022E 2023E CAGR Volumes (MBbls) 2,618.2 2,400.0 1,300.0 3,000.0 3,000.0 3,000.0 3,000.0 Total Gross Margin $10.8 $3.4 $1.6 $7.2 $7.2 $7.2 $7.2 Operating Expenses (2.8) (2.4) (2.7) (2.7) (2.7) (2.7) (2.7) EBITDA $8.0 $1.0 ($1.1) $4.5 $4.5 $4.5 $4.5 35.7% Maintenance Capital Expenditures -- (3.4) (3.8) -- -- -- -- Growth Capital Expenditures -- -- -- -- -- -- -- Free Cash Flow $8.0 ($2.4) ($4.9) $4.5 $4.5 $4.5 $4.5 NA Source: AMID management 86

Preliminary Draft Subject to Change Detailed Segment Financial Projections NGL Pipeline Interests (Wilprise, Tri-States, Cayenne) ($ in millions) Volume (MBoed) Asset EBITDA1 120.9 123.8 120.6 117.1 $15.8 112.1 104.5 $15.3 $15.4 $13.8 $14.2 87.8 $13.2 $8.1 2017A 2018A 2019E 2020E 2021E 2022E 2023E 2017A 2018A 2019E 2020E 2021E 2022E 2023E Distributions1 $15.7 $15.5 $15.2 $14.4 $13.4 $11.1 $7.3 2017A 2018A 2019E 2020E 2021E 2022E 2023E Source: AMID management 1. Pro rata for AMID’s 25.3% ownership of Wilprise, 16.7% ownership of Tri-States and 50.0% ownership of Cayenne 87 Preliminary Draft Subject to Change Detailed Segment Financial Projections NGL JV Interests ($ in millions) AMID Financial Projections For the Twelve Month Ending December 31, 2018A – 2023E 2017A 2018A 2019E 2020E 2021E 2022E 2023E CAGR NGL Volumes (MBpd) Cayenne (50.0% Ownership) -- 30.0 33.9 33.9 32.8 29.1 25.8 Tri States (16.7% Ownership) 53.8 50.4 55.1 57.1 55.9 54.8 53.7 Wilprise (25.0% Ownership) 34.0 36.7 31.9 32.9 31.9 28.2 25.0 NGL Volumes 87.8 117.1 120.9 123.8 120.6 112.1 104.5 (2.2%) Gross Margin Cayenne (50% Ownership) $-- $13.9 $15.7 $15.9 $15.4 $13.6 $12.1 (2.7%) Tri States (16.7% Ownership) 50.5 48.3 51.6 53.8 52.9 52.2 51.4 1.3% Wilprise (25.3% Ownership) 5.2 5.7 4.8 4.9 4.8 4.2 3.7 (8.0%) Operating Expenses Cayenne (50% Ownership) $-- ($1.3) ($1.0) ($1.0) ($1.0) ($1.0) ($1.0) Tri States (16.7% Ownership) (8.1) (10.2) (10.0) (10.0) (10.0) (10.0) (10.0) Wilprise (25.3% Ownership) (1.0) (0.9) (0.8) (0.8) (0.8) (0.8) (0.8) EBITDA Cayenne (50% Ownership) $-- $12.5 $14.7 $14.9 $14.4 $12.6 $11.1 (2.4%) Tri States (16.7% Ownership) 42.4 38.1 41.6 43.8 42.9 42.2 41.4 1.7% Wilprise (25.3% Ownership) 4.2 4.8 3.9 4.1 3.9 3.4 2.9 (9.6%) Maintenance Capital Expenditures Cayenne (50% Ownership) $-- $-- $-- $-- $-- $-- $-- Tri States (16.7% Ownership) -- -- -- -- -- -- -- Wilprise (25.3% Ownership) -- -- -- -- -- -- -- Growth Capital Expenditures Cayenne (50% Ownership) $-- $-- $-- $-- $-- $-- $-- Tri States (16.7% Ownership) -- -- -- -- -- -- -- Wilprise (25.3% Ownership) -- -- -- -- -- -- -- Source: AMID management 88

Preliminary Draft Subject to Change C. Preliminary Valuation of Natural Gas Gathering & Processing Preliminary Draft Subject to Change Preliminary Valuation of Natural Gas Gathering and Processing Summary Valuation ($ in millions) Peer Trading Analysis Peer Trading Analysis Discounted Cash Flow Analysis Precedent M&A Analysis 2019E 2020E $800.0 $700.0 $592.9 $600.0 $537.4 $500.0 $447.7 $477.7 $424.3 $400.0 $428.1 $347.1 $300.0 $234.3 $200.0 $100.0 $-- 7.5% – 8.5% WACC 2019E and 2020E Multiple Range Selected 2019E Multiple Range Selected 2020E Multiple Range Selected 2023E EBITDA Perpetuity Growth 2019E EBITDA 2020E EBITDA 2019E EBITDA 2020E EBITDA Multiple: Rate: Multiple Multiple Multiple Multiple 7.0 x – 9.0x 0.75% – 1.25% 7.0 x – 9.0x 7.0 x – 9.0x 9.0 x – 11.0x 8.0 x – 9.0x 89

Preliminary Draft Subject to Change Preliminary Valuation of Natural Gas Gathering and Processing Discounted Cash Flow Analysis – Assumptions Evercore utilized the following assumptions to analyze AMID natural gas gathering and processing assets’ discounted cash flows: Discounted the projected cash flows to June 30, 2019 EBITDA and capital expenditures through December 31, 2023E per the AMID Financial Projections, assuming no asset sales Unitholder effective tax rate of 29.6% (80.0% of taxable income at 37.0% tax bracket) Mid-point discount rate of 8.0% utilizing WACC based on CAPM Terminal value based on a (i) 7.0x to 9.0x EBITDA exit multiple and (ii) 0.75% to 1.25% perpetuity growth rate Tax depreciation assumed to equal maintenance capital expenditures in perpetuity 90 Preliminary Draft Subject to Change Preliminary Valuation of Natural Gas Gathering and Processing Discounted Cash Flow Analysis ($ in millions) For the Six Months Ending December 31, For the Years Ending December 31, EBITDA Perpetuity 2019E 2020E 2021E 2022E 2023E Multiple Growth EBITDA $23.2 $59.7 $68.6 $71.8 $73.1 $73.1 $73.1 Less: Tax Depreciation and Amortization (550.6) (58.0) (32.4) (29.1) (22.5) (3.0) EBIT ($527.4) $1.7 $36.2 $42.7 $50.7 $70.1 Less: Cash Taxes -- (0.1) (1.7) (2.0) (2.4) (25.9) EBIAT ($527.4) $1.7 $34.5 $40.7 $48.3 $44.2 Plus: Tax Depreciation and Amortization 550.6 58.0 32.4 29.1 22.5 3.0 Less: Growth Capital Expenditures (42.4) (55.0) (29.4) (26.1) (25.1) --Less: Maintenance Capital Expenditures (1.2) (3.0) (3.0) (3.0) (3.0) (3.0) Unlevered Free Cash Flow ($20.3) $1.7 $34.5 $40.7 $42.7 $44.2 EBITDA Multiple / Perpetuity Growth Rate 8.0x 1.0% Terminal Value $584.9 $637.4 PV of Terminal Value @ 8.0% Discount Rate $413.7 $450.8 Plus: PV of Unlevered Free Cash Flow @ 8.0% Discount Rate 74.8 Implied Enterprise Value $488.5 $525.6 Sensitivity Analysis EBITDA Multiple Perpetuity Growth Rate 6.0x 7.0x 8.0x 9.0x 10.0x 0.50% 0.75% 1.00% 1.25% 1.50% 7.0% $401.0 $454.9 $508.8 $562.7 $616.7 7.0% $581.1 $602.6 $625.8 $651.1 $678.6 CC 7.5% 392.9 445.7 498.5 551.3 604.1 CC 7.5% 534.1 552.3 571.8 592.9 615.8 WA 8.0% 385.1 436.8 488.5 540.2 591.9 WA 8.0% 493.4 509.0 525.6 543.4 562.7 8.5% 377.4 428.1 478.7 529.4 580.0 8.5% 457.9 471.3 485.6 500.9 517.2 9.0% 369.9 419.6 469.2 518.8 568.4 9.0% 426.7 438.3 450.7 463.9 477.9 91

Preliminary Draft Subject to Change Preliminary Valuation of Natural Gas Gathering and Processing Precedent M&A Transaction Analysis ($ in millions) Precedent Transactions – Low Growth Natural Gas Gathering and Processing Date Transaction EBITDA Announced Acquiror / Target (Seller) Value Multiple 11/2018 Elevate Midstream Partners / Orion Pipeline NA 7.6x 11/2016 Tesoro Logistics LP / Williston G&P Assets (Whiting Oil and Gas Corp.) $700.0 6.7 11/2016 CONE Midstream Partners LP / 25% Additional Interest in Anchor Systems (CONSOL Energy Inc. and Noble Energy, Inc.) 248.0 7.5 07/2016 Sanchez Production Partners LP / 50% interest in Carnero Gathering, LLC (Sanchez Energy Corporation) 44.4 6.3 09/2015 Sanchez Production Partners LP / Pipeline, Gathering and Compression Assets in Western Catarina (Sanchez Energy Corporation) 345.8 9.4 08/2015 Azure Midstream Partners, LP / Azure ETG, LLC gathering and processing system (Azure Midstream Energy, LLC) 83.0 6.2 03/2014 Summit Midstream Partners, LP / Red Rock Gathering Company, LLC (Summit Midstream Partners, LLC) 305.0 8.6 05/2013 MarkWest Energy Partners, L.P. / Granite Wash Gathering and Processing Assets (Chesapeake Energy Corporation) 245.0 8.2 02/2013 Western Gas Partners, LP / 33.75% Interest in Liberty and Rome Gas Gathering Systems (Anadarko Petroleum Corporation) 490.0 7.6 08/2012 Eagle Rock Energy Partners / Sunray and Hemphill processing plants and associated 2,500 mile gathering system (BP America Production Co.) 227.5 9.5 All Transactions Mean 7.7x Median 7.6 Summary Results 2019E EBITDA $38.6 Plus: Adjustment for Full Year Effect of Acquisition of Pascagoula Plant 1.6 Relevant 2019E EBITDA $40.2 Relevant EBITDA Multiple 7.0x - 9.0x Implied Enterprise Value as of December 31, 2019E $281.3 - $361.6 Implied Enterprise Value Range on June 30, 2019E @ 8.0% Discount Rate $275.9 $354.7 Less: Present Value of June 30, 2019E to December 31, 2019E Growth Capital Expenditures @ 8.0% Discount Rate ($41.6) Implied Enterprise Value Range - 2019E EBITDA $234.3 - $313.2 2020E EBITDA $59.7 Plus: Adjustment for Full Year Effect of Longview Expansion 4.8 Relevant 2020E EBITDA $64.5 Relevant EBITDA Multiple 7.0x - 9.0x Implied Enterprise Value as of December 31, 2020E $451.8 - $580.8 Implied Enterprise Value Range on June 30, 2019E @ 8.0% Discount Rate $418.3 $537.8 Less: Present Value of June 30, 2019E to December 31, 2020E Growth Capital Expenditures @ 8.0% Discount Rate ($90.1) Implied Enterprise Value Range - 2020E EBITDA $328.1 - $447.7 Implied Enterprise Value Range $234.3 $447.7 Source: Public filings, Wall street research 92 Preliminary Draft Subject to Change Preliminary Valuation of Natural Gas Gathering and Processing Peer Group Trading Analysis ($ in millions, except per unit or share amounts) Price Equity Enterprise Enterprise Value / EBITDA Distribution Yield Distribution Total Partnership / Corporation 3/7/19 Value Value 2019E 2020E Current 2019E Growth Return Natural Gas Gathering and Processing CNX Midstream Partners LP $15.29 $993.1 $1,534.2 7.2x 6.2x 9.4% 10.3% 8.8% 18.2% Crestwood Equity Partners LP 32.05 2,282.6 4,828.3 10.2 8.9 7.5% 7.5% 3.6% 11.0% DCP Midstream Partners, LP 31.49 4,605.2 10,691.6 8.9 7.9 9.9% 9.9% 1.6% 11.5% Enable Midstream Partners, LP 15.01 6,503.0 11,173.0 9.8 9.5 8.5% 8.5% 3.7% 12.2% Hess Midstream Partners LP 22.82 1,270.9 1,236.3 11.2 9.2 6.5% 7.1% 11.3% 17.8% Noble Midstream Partners LP 36.66 1,458.6 2,751.1 10.2 7.4 6.4% 7.2% 17.7% 24.1% Summit Midstream Partners, LP 10.45 874.7 2,740.9 8.5 8.1 22.0% 22.0% NM NM Targa Resources Corp. 40.09 9,306.6 15,929.7 12.8 10.2 9.1% 9.1% 3.3% 12.3% Mean 9.9x 8.4x 9.9% 10.2% 7.1% 15.3% Median 10.0 8.5 8.8% 8.8% 3.7% 12.3% Summary Results 2019E EBITDA $38.6 Relevant EBITDA Multiple 9.0x - 11.0x Implied Enterprise Value Based on 2019E EBITDA $347.1 - $424.3 2020E EBITDA $59.7 Relevant EBITDA Multiple 8.0x - 9.0x Implied Enterprise Value Based on 2020E EBITDA $477.7 - $537.4 Source: FactSet, Public filings 93

Preliminary Draft Subject to Change D. Preliminary Valuation of Natural Gas Transportation Preliminary Draft Subject to Change Preliminary Valuation of Natural Gas Transportation Summary Valuation ($ in millions) Peer Trading Analysis Discounted Cash Flow Analysis Precedent M&A Analysis 2019E 2020E $350.0 $325.0 $300.0 $275.0 $255.7 $258.3 $250.0 $236.0 $234.6 $225.0 $212.3 $211.4 $200.0 $186.8 $175.0 $150.0 $165.5 $125.0 $100.0 $75.0 $50.0 10.0% – 11.0% WACC 2019E and 2020E Multiple Range Selected 2019E Multiple Range Selected 2020E Multiple Range Selected 2023E EBITDA Perpetuity Growth 2019E EBITDA 2020E EBITDA 2019E EBITDA 2020E EBITDA Multiple: Rate: Multiple Multiple Multiple Multiple 9.0 x – 11.0x 1.75% – 2.25% 9.0 x – 11.0x 9.0 x – 11.0x 9.5 x – 10.5x 9.0 x – 11.0x 94

Preliminary Draft Subject to Change Preliminary Valuation of Natural Gas Transportation Discounted Cash Flow Analysis – Assumptions Evercore utilized the following assumptions to analyze AMID natural gas transportation assets’ discounted cash flows: Discounted the projected cash flows to June 30, 2019 EBITDA and capital expenditures through December 31, 2023E per the AMID Financial Projections Unitholder effective tax rate of 29.6% (80.0% of taxable income at 37.0% tax bracket) Mid-point discount rate of 10.5% utilizing WACC based on CAPM Terminal value based on a (i) 9.0x to 11.0x EBITDA exit multiple and (ii) 1.75% to 2.25% perpetuity growth rate Tax depreciation assumed to equal maintenance capital expenditures in perpetuity 95 Preliminary Draft Subject to Change Preliminary Valuation of Natural Gas Transportation Discounted Cash Flow Analysis ($ in millions) For the Six Months Ending December 31, For the Years Ending December 31, EBITDA Perpetuity 2019E 2020E 2021E 2022E 2023E Multiple Growth EBITDA $11.3 $23.5 $25.2 $26.0 $26.0 $26.0 $26.0 Less: Tax Depreciation and Amortization (211.4) (4.6) (4.4) (3.5) (2.8) (3.5) EBIT ($200.0) $18.9 $20.8 $22.5 $23.2 $22.5 Less: Cash Taxes -- (0.9) (1.0) (1.1) (1.1) (8.3) EBIAT ($200.0) $18.0 $19.8 $21.4 $22.1 $14.2 Plus: Tax Depreciation and Amortization 211.4 4.6 4.4 3.5 2.8 3.5 Less: Growth Capital Expenditures (3.8) (1.1) (0.9) -- -- --Less: Maintenance Capital Expenditures (1.6) (3.5) (3.5) (3.5) (3.5) (3.5) Unlevered Free Cash Flow $5.9 $18.0 $19.8 $21.4 $21.4 $14.2 EBITDA Multiple / Perpetuity Growth Rate 10.0x 2.00% Terminal Value $260.4 $170.4 PV of Terminal Value @ 10.5% Discount Rate $166.1 $108.7 Plus: PV of Unlevered Free Cash Flow @ 10.5% Discount Rate 68.5 Implied Enterprise Value $234.6 $177.2 Sensitivity Analysis EBITDA Multiple Perpetuity Growth Rate 8.0x 9.0x 10.0x 11.0x 12.0x 1.75% 1.75% 2.00% 2.25% 2.25% 9.5% $208.4 $225.7 $243.0 $260.3 $277.6 9.5% $193.8 $193.8 $198.3 $203.0 $203.0 ACC 10.0% 204.9 221.8 238.8 255.7 272.7 ACC 10.0% 183.2 183.2 187.1 191.2 191.2 W 10.5% 201.4 218.0 234.6 251.2 267.9 W 10.5% 173.8 173.8 177.2 180.8 180.8 11.0% 198.0 214.3 230.6 246.9 263.1 11.0% 165.5 165.5 168.4 171.5 171.5 11.5% 194.7 210.7 226.6 242.6 258.6 11.5% 157.9 157.9 160.5 163.3 163.3 96

Preliminary Draft Subject to Change Preliminary Valuation of Natural Gas Transportation Precedent M&A Transaction Analysis ($ in millions) Precedent Transactions – Non-FERC Natural Gas Transportation Transaction Date Transaction Value / Announced Acquiror / Target (Seller) Value EBITDA 1/2019 NEXUS Gas Transmission, LLC (Enbridge Inc.; DTE Energy Company) / Generation Pipeline LLC $160.0 14.4x 8/2015 NextEra Energy Partners, LP / NET Midstream (ArcLight Capital Partners) 2,000.0 13.3 3/2014 Southcross Energy Partners LP / 50 miles of natural gas pipelines near Corpus Christi, Texas (Onyx Midstream LP) 40.0 7.0 4/2010 Regency Energy Partners / 7.0% of Haynesville Joint Venture (GE Energy Financial Services) 92.0 9.9 11/2009 American Midstream Partners, LP. / Enbridge Pipelines (Midla) LLC and Enbridge Pipelines (AlaTenn) LLC 151.0 11.2 Median 10.6x Mean 10.4 Precedent Transactions – FERC-Regulated Natural Gas Transportation Transaction Transaction Date Value Value / Announced Acquiror / Target (Seller) ($MM) EBITDA 2/2018 Tallgrass Energy GP / 25.01% interest in Rockies Express Pipeline LLC (Tallgrass Development LP) $1,044.0 6.4x 6/2017 TC Pipelines / 49.3% interest in Iroquois Gas Transmission System, LP and 11.8% interest in Portland Natural Gas Transmission (TransCanada Corp.) 765.0 10.9 4/2017 Tallgrass Energy Partners, LP / 24.99% interest in Rockies Express Pipeline LLC (Tallgrass Development, LP) 1,043.5 6.6 10/2016 Dominion Midstream Partners / Questar Pipeline LLC (Dominion Resources) 1,725.0 10.0 7/2016 Southern Company / 50% Interest in Southern Natural Gas Pipeline System (Kinder Morgan) 2,075.0 10.4 5/2016 Tallgrass Energy Partners, LP / 25% interest in Rockies Express Pipeline LLC (Sempra U.S. Gas and Power) 1,084.0 6.9 11/2015 Kinder Morgan, Inc. and Brookfield Infrastructure Partners LP / Natural Gas Pipeline Company of America LLC (Myria Holdings, Inc.) 3,400.0 13.1 8/2015 Dominion Midstream Partners, LP / 26% interest in Iroquois Gas Transmission System, LP (National Grid and New Jersey Resources Corp.) 286.5 9.8 5/2015 GE Energy Financial Services and Caisse de dépôt et placement du Québec / Southern Star Central Corp (Morgan Stanley Infrastructure) 1,550.2 11.6 4/2015 Dominion Midstream Partners, LP / Dominion Carolina Gas Transmission, LLC (Dominion Resources, Inc.) 495.0 13.0 2/2015 TC Pipelines, LP / 30% interest in Gas Transmission Northwest LLC (TransCanada Corporation) 446.0 10.4 12/2014 Dominion Resources, Inc. / Carolina Gas Transmission (SCANA Corporation) 492.9 13.0 10/2014 TC Pipelines, LP / 49.9% interest in Portland Natural Gas Transmission System (TransCanada Corp.) 233.0 10.1 10/2014 TC Pipelines, LP / 30% interest in Bison Pipeline LLC (TransCanada Corporation) 215.0 10.2 4/2014 El Paso Pipeline Partners, LP / 50% interest in Ruby Pipeline and Gulf LNG and 47.5% interest in Young Gas Storage (Kinder Morgan , Inc.) 2,000.0 9.0 7/2013 EQT Midstream Partners, LP / Sunrise Pipeline, LLC (EQT Corporation) 540.0 9.9 5/2013 TC PipeLines, LP / 45% interest in Gas Transmission Northwest LLC and Bison Pipeline LLC (TransCanada Corporation) 1,050.0 11.0 8/2012 Morgan Stanley Infrastructure Partners / Remaining 60% interest in Southern Star Central Corp (General Electric) 975.0 9.0 8/2012 Tallgrass Energy Partners, LP / Interstate Gas Transmission, Trailblazer Pipeline Co., Casper-Douglas, West Frenchie Draw & 50% interest in REX (Kinder Morgan, Inc.) 3,300.0 8.3 8/2012 Kinder Morgan Energy Partners, LP / Tennessee Gas Pipeline & 50% interest in El Paso Natural Gas (Kinder Morgan, Inc.) 6,220.0 8.0 7/2011 Energy Transfer Partners, LP / 50% interest in Citrus Corp. (Energy Transfer Equity, LP) 2,000.0 10.9 4/2011 TC Pipelines / 25% interest in Gas Transmission Northwest LLC (TransCanada Corporation) 405.0 9.5 4/2011 TC Pipelines / 25% interest in Bison Pipeline LLC (TransCanada Corporation) 200.0 12.5 Median 10.1x Mean 9.9 Source: Public filings, Wall street research 97 Preliminary Draft Subject to Change Preliminary Valuation of Natural Gas Transportation Precedent M&A Transaction Analysis ($ in millions) Summary Results 2019E EBITDA $22.3 Relevant EBITDA Multiple 9.0x - 11.0x Implied Enterprise Value as of December 31, 2019E $201.1 - $245.8 Implied Enterprise Value Range on June 30, 2019E @ 10.5% Discount Rate $196.1 $239.7 Less: Present Value of June 30, 2019E to December 31, 2019E Growth Capital Expenditures @ 10.5% Discount Rate ($3.7) Implied Enterprise Value Range - 2019E EBITDA $192.4 - $236.0 2020E EBITDA $23.5 Relevant EBITDA Multiple 9.0x - 11.0x Implied Enterprise Value as of December 31, 2020E $211.4 - $258.3 Implied Enterprise Value Range on June 30, 2019E @ 10.5% Discount Rate $191.3 $233.8 Less: Present Value of June 30, 2019E to December 31, 2020E Growth Capital Expenditures @ 10.5% Discount Rate ($4.4) Implied Enterprise Value Range - 2020E EBITDA $186.8 - $229.3 Implied Enterprise Value Range $186.8 $236.0 Source: Public filings, Wall street research 98

Preliminary Draft Subject to Change Preliminary Valuation of Natural Gas Transportation Peer Group Trading Analysis ($ in millions, except per unit / share amounts) Price Equity Enterprise Enterprise Value / EBITDA Distribution Yield Distribution Total Partnership / Corporation 3/7/19 Value Value 2019E 2020E Current 2019E Growth Return Natural Gas Transportation EQT Midstream Partners, LP $40.51 $8,404.1 $12,468.2 9.7x 7.7x 11.0% 11.5% 5.6% 16.6% Enable Midstream Partners, LP 15.01 6,503.0 11,173.0 9.8 9.5 8.5% 8.5% 3.7% 12.2% TC PipeLines, LP 33.72 2,453.5 4,600.5 10.2 10.1 7.7% 7.7% --% 7.7% Tallgrass Energy, LP 23.35 6,543.6 9,740.0 10.0 10.9 8.9% 9.2% 5.4% 14.3% The Williams Companies, Inc. 26.94 32,745.1 56,363.1 11.2 10.5 5.6% 5.6% 9.9% 15.5% Mean 10.2x 9.7x 8.3% 8.5% 4.9% 13.3% Median 10.0 10.1 8.5% 8.5% 5.4% 14.3% Summary Results 2019E EBITDA $22.3 Relevant EBITDA Multiple 9.5x - 10.5x Implied Enterprise Value Based on 2019E EBITDA $212.3 - $234.6 2020E EBITDA $23.5 Relevant EBITDA Multiple 9.0x - 11.0x Implied Enterprise Value Based on 2020E EBITDA $211.4 - $258.3 99 Preliminary Draft Subject to Change E. Preliminary Valuation of Offshore Pipelines (Excl. Delta House)

Preliminary Draft Subject to Change Preliminary Valuation of Offshore Pipelines (Excl. Delta House) Summary Valuation ($ in millions) Peer Trading Analysis Peer Trading Analysis Discounted Cash Flow Analysis Precedent M&A Analysis 2019E 2020E $1,000.0 $900.0 $800.0 $784.4 $751.6 $700.0 $581.7 $589.2 $600.0 $601.3 $588.3 $500.0 $450.2 $400.0 $433.8 $300.0 $200.0 Other Offshore Pipelines Destin – Okeanos $100.0 $-- 8.0% – 9.0% WACC 2019E and 2020E Multiple Range Selected 2019E Multiple Range Selected 2020E Multiple Range Selected 2023E EBITDA Perpetuity Growth 2019E EBITDA 2020E EBITDA 2019E EBITDA 2020E EBITDA Multiple: Rate: Multiple Multiple Multiple Multiple 6.0 x – 8.0x (1.0%) – 1.0% 6.0 x – 8.0x 6.0 x – 8.0x 8.0 x – 10.0x 7.5 x – 10.0x 100 Preliminary Draft Subject to Change Preliminary Valuation of Offshore Pipelines (Excl. Delta House) Discounted Cash Flow Analysis – Assumptions Evercore utilized the following assumptions to analyze AMID offshore pipeline assets’ discounted cash flows: Discounted the projected cash flows to June 30, 2019 EBITDA and capital expenditures through December 31, 2023E per the AMID Financial Projections Unitholder effective tax rate of 29.6% (80.0% of taxable income at 37.0% tax bracket) Mid-point discount rate of 8.5% utilizing WACC based on CAPM Terminal value based on a (i) 6.0x to 8.0x EBITDA exit multiple and (ii) (1.00%) to 1.00% perpetuity growth rate Tax depreciation assumed to equal maintenance capital expenditures in perpetuity 101

Preliminary Draft Subject to Change Preliminary Valuation of Offshore Pipelines (Excl. Delta House) Discounted Cash Flow Analysis – Okeanos and Destin ($ in millions) AMID Financial Projections For the Six Months Ending December 31, For the Years Ending December 31, EBITDA Perpetuity 2019E 2020E 2021E 2022E 2023E Multiple Growth EBITDA $34.7 $65.9 $56.8 $51.9 $44.8 $44.8 $44.8 Less: Tax Depreciation and Amortization (419.4) -- -- -- -- --EBIT ($384.7) $65.9 $56.8 $51.9 $44.8 $44.8 Less: Cash Taxes -- (3.1) (2.7) (2.5) (2.1) (16.6) EBIAT ($384.7) $62.8 $54.1 $49.5 $42.7 $28.2 Plus: Tax Depreciation and Amortization 419.4 -- -- -- -- --Less: Growth Capital Expenditures -- -- -- -- -- --Less: Maintenance Capital Expenditures -- -- -- -- -- --Less: Change in Deferred Revenue (1.5) (3.1) (3.1) (3.1) (3.1) --Unlevered Free Cash Flow $33.1 $59.7 $51.1 $46.4 $39.6 $28.2 EBITDA Multiple / Perpetuity Growth Rate 7.0x --% Terminal Value $313.5 $331.9 PV of Terminal Value @ 8.5% Discount Rate $217.1 $229.9 Plus: PV of Unlevered Free Cash Flow @ 8.5% Discount Rate 195.9 Implied Enterprise Value $413.0 $425.8 Implied Enterprise Value (AMID’s 66.7% Share) $275.5 $284.0 Sensitivity Analysis EBITDA Multiple Perpetuity Growth Rate 5.0x 6.0x 7.0x 8.0x 9.0x (2.0%) (1.0%) --% 1.0% 2.0% 7.5% $240.8 $262.4 $284.0 $305.5 $327.1 7.5% $273.2 $291.3 $314.2 $344.1 $385.0 ACC 8.0% 237.4 258.6 279.7 300.8 321.9 ACC 8.0% 262.2 278.2 298.2 323.8 358.1 W 8.5% 234.1 254.8 275.5 296.2 316.9 W 8.5% 252.3 266.5 284.0 306.2 335.2 9.0% 230.8 251.1 271.4 291.6 311.9 9.0% 243.3 255.9 271.4 290.7 315.6 9.5% 227.7 247.5 267.4 287.2 307.1 9.5% 235.0 246.3 260.0 277.0 298.5 102 Preliminary Draft Subject to Change Preliminary Valuation of Offshore Pipelines (Excl. Delta House) Precedent M&A Transaction Analysis ($ in millions) Precedent Transactions – Offshore Gathering (Excluding Corridor Pipelines) Date Transaction EBITDA Announced Acquiror / Target (Seller) Value Multiple 10/2018 BP Midstream Partners LP / Interest in Mardi Gras Transportation System Company LLC, URSA Oil Pipeline Company LLC and KM-Phoenix Holdings LLC (BP p.l.c.) $486.0 9.4x 05/2018 Shell Midstream Partners, L.P. / Amberjack Pipeline Company LLC (Shell) 1,220.0 8.0 10/2017 American Midstream Partners, LP / 17% Interest in Destin Pipeline (ArcLight Capital Partners, LLC) 30.0 6.3 10/2017 American Midstream Partners, LP / 15.5% interest in Delta House (ArcLight Capital Partners, LLC) 125.4 7.1 08/2017 American Midstream Partners, LP / Remaining Interest in MPOG and AmPan (ArcLight Capital Partners, LLC) 52.0 7.0 06/2017 American Midstream Partners, LP / Vioska Knoll gathering system (Genesis Energy LP) 32.0 7.0 05/2017 Shell Midstream Partners, LP / The Delta, Na Kika and Refinery Gas pipelines (Shell Pipeline Company) 630.0 8.4 11/2016 American Midstream Partners, LP / 6.2% in Delta House (ArcLight Capital Partners, LLC) 48.8 6.0 09/2016 Shell Midstream Partners, L.P. / 20.0% interest in Mars Oil Pipeline Company and 49.0% interest in Odyssey Pipeline L.L.C. (Shell Pipeline Company LP) 350.0 8.4 11/2015 Shell Midstream Partners, L.P. / 100.0% Interest in Auger Pipeline System and Lockport Crude Terminal (Shell Pipeline Company LP) 390.0 8.6 07/2015 Shell Midstream Partners, L.P. / 36.0% interest in Poseidon Oil Pipeline Company, LLC (Shell Oil Products US) 350.0 9.5 04/2016 American Midstream Partners, LP / GoM offshore pipeline assets (ArcLight Capital Partners, LLC) 225.0 6.0 08/2015 American Midstream Partners, LP / 12.9% Interest in Delta House (ArcLight Capital Partners, LLC) 162.0 5.0 10/2011 Genesis Energy, L.P. / 28% interest in Poseidon Oil Pipeline Company, LLC, 29% interest in Odyssey Pipeline LLC and 23% interest in the Eugene Island Pipeline System (Marathon Oil Corporation) 179.0 8.0 06/2007 Williams Partners L.P. / 20.0% interest in Discovery Producer Services LLC (Williams) 78.0 7.1 Mean 7.5x Median 7.1 Source: Public filings, Wall street research 103

Preliminary Draft Subject to Change Preliminary Valuation of Offshore Pipelines (Excl. Delta House) Precedent M&A Transaction Analysis – Okeanos and Destin ($ in millions) Summary Results 2019E EBITDA $62.1 Relevant EBITDA Multiple 6.0x - 8.0x Implied Enterprise Value as of December 31, 2019E $372.7 - $497.0 Implied Enterprise Value Range on June 30, 2019E @ 8.5% Discount Rate $365.2 $486.9 Less: Present Value of June 30, 2019E to December 31, 2019E Growth Capital Expenditures @ 8.5% Discount Rate $-- Implied Enterprise Value Range - 2019E EBITDA $365.2 - $486.9 2020E EBITDA $65.9 Relevant EBITDA Multiple 6.0x - 8.0x Implied Enterprise Value as of December 31, 2020E $395.5 - $527.3 Implied Enterprise Value Range on June 30, 2019E @ 8.5% Discount Rate $364.5 $486.0 Less: Present Value of June 30, 2019E to December 31, 2020E Growth Capital Expenditures @ 8.5% Discount Rate $-- Implied Enterprise Value Range - 2020E EBITDA $364.5 - $486.0 Implied Enterprise Value Range $364.5 - $486.9 Implied Enterprise Value Range (AMID’s 66.7% Share) $243.1 $324.8 104 Preliminary Draft Subject to Change Preliminary Valuation of Offshore Pipelines (Excl. Delta House) Peer Group Trading Analysis – Okeanos and Destin ($ in millions, except per unit amounts) Price Equity Enterprise Enterprise Value / EBITDA Distribution Yield Distribution Total Partnership / Corporation 3/7/19 Value Value 2019E 2020E Current 2019E Growth Return Offshore Pipelines Plains All American Pipeline, L.P. $23.97 $17,416.1 $28,851.1 10.5x 10.4x 5.0% 5.5% 9.6% 14.6% Genesis Energy, L.P. 21.63 2,650.5 6,834.2 9.8 9.3 10.0% 10.2% 0.5% 10.4% Shell Midstream Partners, L.P. 18.57 4,241.0 6,174.2 8.2 6.8 8.6% 9.3% 4.4% 13.0% Mean 9.5x 8.8x 7.9% 8.3% 4.8% 12.7% Median 9.8 9.3 8.6% 9.3% 4.4% 13.0% Summary Results 2019E EBITDA $62.1 Relevant EBITDA Multiple 8.0x - 10.0x Implied Enterprise Value Based on 2019E EBITDA $497.0 - $621.2 Implied Enterprise Value (AMID’s 66.7% Share) $331.5 - $414.3 2020E EBITDA $65.9 Relevant EBITDA Multiple 7.5x - 10.0x Implied Enterprise Value Based on 2020E EBITDA $494.4 - $659.2 Implied Enterprise Value (AMID’s 66.7% Share) $329.8 - $439.7 Source: FactSet, Public Filings 105

Preliminary Draft Subject to Change Preliminary Valuation of Offshore Pipelines (Excl. Delta House) Discounted Cash Flow Analysis – Other Offshore Pipelines ($ in millions) AMID Financial Projections For the Six Months Ending December 31, For the Years Ending December 31, EBITDA Perpetuity 2019E 2020E 2021E 2022E 2023E Multiple Growth EBITDA $16.6 $34.5 $32.8 $30.4 $28.0 $28.0 $28.0 Less: Tax Depreciation and Amortization (232.3) (4.0) (4.0) (4.0) (3.2) (4.0) EBIT ($215.7) $30.5 $28.8 $26.4 $24.8 $24.0 Less: Cash Taxes -- (1.4) (1.4) (1.3) (1.2) (8.9) EBIAT ($215.7) $29.0 $27.4 $25.2 $23.7 $15.1 Plus: Tax Depreciation and Amortization 232.3 4.0 4.0 4.0 3.2 4.0 Less: Growth Capital Expenditures -- -- -- -- -- --Less: Maintenance Capital Expenditures (4.3) (4.0) (4.0) (4.0) (4.0) (4.0) Unlevered Free Cash Flow $12.3 $29.0 $27.4 $25.2 $22.9 $15.1 EBITDA Multiple / Perpetuity Growth Rate 7.0x --% Terminal Value $196.2 $178.1 PV of Terminal Value @ 8.5% Discount Rate $135.9 $123.4 Plus: PV of Unlevered Free Cash Flow @ 8.5% Discount Rate 98.3 Implied Enterprise Value $234.3 $221.7 Sensitivity Analysis EBITDA Multiple Perpetuity Growth Rate 5.0x 6.0x 7.0x 8.0x 9.0x (2.0%) (1.0%) --% 1.0% 2.0% 7.5% $201.4 $221.7 $241.9 $262.2 $282.4 7.5% $213.0 $227.6 $246.0 $270.1 $303.0 ACC 8.0% 198.4 218.2 238.1 257.9 277.7 ACC 8.0% 204.2 217.1 233.1 253.8 281.3 W 8.5% 195.4 214.8 234.3 253.7 273.1 W 8.5% 196.2 207.6 221.7 239.6 262.9 9.0% 192.5 211.5 230.6 249.6 268.6 9.0% 188.9 199.1 211.6 227.1 247.1 9.5% 189.7 208.3 226.9 245.6 264.2 9.5% 182.3 191.4 202.4 216.1 233.4 106 Preliminary Draft Subject to Change Preliminary Valuation of Offshore Pipelines (Excl. Delta House) Precedent M&A Transaction Analysis – Other Offshore Pipelines ($ in millions) Summary Results 2019E EBITDA $33.7 Relevant EBITDA Multiple 6.0x - 8.0x Implied Enterprise Value as of December 31, 2019E $202.4 - $269.8 Implied Enterprise Value Range on June 30, 2019E @ 8.5% Discount Rate $198.3 $264.4 Less: Present Value of June 30, 2019E to December 31, 2019E Growth Capital Expenditures @ 8.5% Discount Rate $-- Implied Enterprise Value Range - 2019E EBITDA $198.3 - $264.4 2020E EBITDA $34.5 Relevant EBITDA Multiple 6.0x - 8.0x Implied Enterprise Value as of December 31, 2020E $206.8 - $275.8 Implied Enterprise Value Range on June 30, 2019E @ 8.5% Discount Rate $190.6 $254.2 Less: Present Value of June 30, 2019E to December 31, 2020E Growth Capital Expenditures @ 8.5% Discount Rate $-- Implied Enterprise Value Range - 2020E EBITDA $190.6 - $254.2 Implied Enterprise Value Range $190.6 - $264.4 107

Preliminary Draft Subject to Change Preliminary Valuation of Offshore Pipelines (Excl. Delta House) Peer Group Trading Analysis – Other Offshore Pipelines ($ in millions) Price Equity Enterprise Enterprise Value / EBITDA Distribution Yield Distribution Total Partnership / Corporation 3/7/19 Value Value 2019E 2020E Current 2019E Growth Return Offshore Pipelines Plains All American Pipeline, L.P. $23.97 $17,416.1 $28,851.1 10.5x 10.4x 5.0% 5.5% 9.6% 14.6% Genesis Energy, L.P. 21.63 2,650.5 6,834.2 9.8 9.3 10.0% 10.2% 0.5% 10.4% Shell Midstream Partners, L.P. 18.57 4,241.0 6,174.2 8.2 6.8 8.6% 9.3% 4.4% 13.0% Mean 9.5x 8.8x 7.9% 8.3% 4.8% 12.7% Median 9.8 9.3 8.6% 9.3% 4.4% 13.0% Summary Results 2019E EBITDA $33.7 Relevant EBITDA Multiple 8.0x - 10.0x Implied Enterprise Value Based on 2019E EBITDA $269.8 - $337.3 2020E EBITDA $34.5 Relevant EBITDA Multiple 7.5x - 10.0x Implied Enterprise Value Based on 2020E EBITDA $258.6 - $344.7 108 Preliminary Draft Subject to Change F. Preliminary Valuation of Delta House

Preliminary Draft Subject to Change Preliminary Valuation of Delta House Summary Valuation – Delta House ($ in millions) Discounted Cash Flow Analysis $500.0 $400.0 $315.6 $300.0 $258.6 $200.0 $100.0 $-- 8.0% – 9.0% WACC 2025E EBITDA Perpetuity Growth Multiple: Rate: 2.0 x – 4.0x (11.0%) – (9.0%) 109 Preliminary Draft Subject to Change Preliminary Valuation of Delta House Discounted Cash Flow Analysis – Assumptions Evercore utilized the following assumptions to analyze AMID’s share of Delta House’s discounted cash flows: Discounted the projected cash flows to June 30, 2019 EBITDA and capital expenditures through December 31, 2023E per the AMID Financial Projections Mid-point discount rate of 8.5% utilizing WACC based on CAPM Terminal value based on a (i) 2.0x to 4.0x EBITDA exit multiple and (ii) (11.00%) to (9.00%) perpetuity growth rate Tax depreciation assumed to equal maintenance capital expenditures in perpetuity 110

Preliminary Draft Subject to Change Preliminary Valuation of Delta House Discounted Cash Flow Analysis – Delta House ($ in millions) AMID Financial Projections For the Six Months Ending December 31, For the Years Ending December 31, EBITDA Perpetuity 2019E 2020E 2021E 2022E 2023E 2024E 2025E Multiple Growth EBITDA $113.7 $242.7 $225.5 $199.8 $175.8 $133.9 $127.2 $71.5 1 $71.5 1 Less: Change in Deferred Revenue 9.8 (84.7) (86.7) (78.0) (78.0) (57.2) (55.6) Less: Change in Other Working Capital (8.9) 22.0 (0.8) 6.2 2.4 3.9 (1.2) Cash Flow Available for Distribution $114.6 $180.0 $138.1 $128.1 $100.2 $80.6 $70.3 $71.5 Less: Class B Carry -- (1.2) (3.5) (3.3) (3.0) (2.4) (2.2) (2.2) (2.2) Class A Cash Flows $114.6 $178.8 $134.6 $124.8 $97.2 $78.2 $68.1 $69.4 3.0x (10%) Terminal Value $208.1 $337.4 PV of Terminal Value @ 8.5% Discount Rate $122.4 $198.5 Plus: PV of Unlevered Free Cash Flow @ 8.5% Discount Rate $653.1 Implied Enterprise Value $775.5 $851.6 Implied Enterprise Value (AMID’s 35.65% Share) $276.5 $303.6 Sensitivity Analysis EBITDA Multiple Perpetuity Growth Rate 1.0x 2.0x 3.0x 4.0x 5.0x (12.0%) (11.0%) (10.0%) (9.0%) (8.0%) 7.5% $253.3 $268.8 $284.2 $299.7 $315.1 7.5% $307.6 $312.2 $317.3 $323.1 $329.6 ACC 8.0% 250.3 265.3 280.3 295.3 310.3 ACC 8.0% 301.3 305.5 310.3 315.6 321.5 W 8.5% 247.4 261.9 276.5 291.0 305.6 W 8.5% 295.3 299.2 303.6 308.5 313.9 9.0% 244.5 258.6 272.7 286.9 301.0 9.0% 289.5 293.2 297.3 301.8 306.8 9.5% 241.7 255.4 269.1 282.8 296.5 9.5% 284.1 287.5 291.2 295.4 300.0 1. GAAP EBITDA adjusted by change in deferred revenue 111 Preliminary Draft Subject to Change G. Preliminary Valuation of Bakken Crude Oil Gathering

Preliminary Draft Subject to Change Preliminary Valuation of Bakken Crude Oil Gathering Summary Valuation ($ in millions) Peer Trading Analysis Peer Trading Analysis Discounted Cash Flow Analysis Precedent M&A Analysis 2019E 2020E $50.0 $41.4 $40.0 $34.9 $32.7 $30.0 $28.2 $22.7 $22.5 $20.0 $17.9 $19.2 $10.0 $-- 12.0% – 13.0% WACC 2019E and 2020E Multiple Range Selected 2019E Multiple Range Selected 2020E Multiple Range Selected 2023E EBITDA Perpetuity Growth 2019E EBITDA 2020E EBITDA 2019E EBITDA 2020E EBITDA Multiple: Rate: Multiple Multiple Multiple Multiple 7.0x – 9.0x 1.75% – 2.25% 7.0x – 9.0x 7.0x – 9.0x 8.0x – 10.0x 7.5x – 9.5x 112 Preliminary Draft Subject to Change Preliminary Valuation of Bakken Crude Oil Gathering Discounted Cash Flow Analysis – Assumptions Evercore utilized the following assumptions to analyze AMID’s Bakken crude oil gathering asset’s discounted cash flows: Discounted the projected cash flows to June 30, 2019 EBITDA and capital expenditures through December 31, 2023E per the AMID Financial Projections, assuming no asset sales Unitholder effective tax rate of 29.6% (80.0% of taxable income at 37.0% tax bracket) Mid-point discount rate of 12.5% utilizing WACC based on CAPM Terminal value based on a (i) 7.0x to 9.0x EBITDA exit multiple and (ii) 1.75% to 2.25% perpetuity growth rate Tax depreciation assumed to equal maintenance capital expenditures in perpetuity 113

Preliminary Draft Subject to Change Preliminary Valuation of Bakken Crude Oil Gathering Discounted Cash Flow Analysis ($ in millions) AMID Financial Projections For the Six Months Ending December 31, For the Years Ending December 31, EBITDA Perpetuity 2019E 2020E 2021E 2022E 2023E Multiple Growth EBITDA $2.0 $4.4 $3.8 $2.9 $2.1 $2.1 $2.1 Less: Tax Depreciation and Amortization (19.9) (0.1) (0.1) (0.1) (0.0) (0.1) EBIT ($17.9) $4.3 $3.7 $2.8 $2.0 $2.0 Less: Cash Taxes -- (0.2) (0.2) (0.1) (0.1) (0.7) EBIAT ($17.9) $4.1 $3.6 $2.7 $1.9 $1.3 Plus: Tax Depreciation and Amortization 19.9 0.1 0.1 0.1 0.0 0.1 Less: Growth Capital Expenditures -- -- -- -- -- --Less: Maintenance Capital Expenditures (0.0) (0.1) (0.1) (0.1) (0.1) (0.1) Unlevered Free Cash Flow $2.0 $4.1 $3.6 $2.7 $1.9 $1.3 EBITDA Multiple / Perpetuity Growth Rate 8.0x 2.0% Terminal Value $16.5 $12.2 PV of Terminal Value @ 12.5% Discount Rate $9.7 $7.2 Plus: PV of Unlevered Free Cash Flow @ 12.5% Discount Rate 11.4 Implied Enterprise Value $21.1 $18.6 Sensitivity Analysis EBITDA Multiple Perpetuity Growth Rate 6.0x 7.0x 8.0x 9.0x 10.0x 1.75% 1.75% 2.00% 2.25% 2.25% 11.5% $19.2 $20.5 $21.7 $23.0 $24.3 11.5% $19.7 $19.7 $19.9 $20.2 $20.2 ACC 12.0% 19.0 20.2 21.4 22.7 23.9 ACC 12.0% 19.0 19.0 19.3 19.5 19.5 W 12.5% 18.7 19.9 21.1 22.4 23.6 W 12.5% 18.5 18.5 18.6 18.8 18.8 13.0% 18.5 19.7 20.9 22.1 23.2 13.0% 17.9 17.9 18.1 18.3 18.3 13.5% 18.3 19.4 20.6 21.8 22.9 13.5% 17.4 17.4 17.6 17.7 17.7 114 Preliminary Draft Subject to Change Preliminary Valuation of Bakken Crude Oil Gathering Precedent M&A Transaction Analysis ($ in millions) Precedent Transactions – Crude Oil Gathering Transaction Date Transaction Value / Announced Acquiror / Target (Seller) Value EBITDA 06/2017 Noble Midstream Partners LP / Additional interest in gathering assets in Delaware and DJ Basins (Noble Energy) $270.0 8.7x 06/2017 Howard Energy Partners / Delaware Basin crude oil gathering and natural gas assets (WPX Energy Inc.) 863.0 10.8 08/2016 PBF Logistics / San Joaquin Valley Pipeline (PBF Energy) 175.0 8.8 05/2015 Summit Midstream Partners, LP / Crude oil and produced water gathering systems and transmission pipelines in the Bakken (Summit Midstream Partners, LLC) 255.0 11.4 01/2015 Kinder Morgan, Inc. / Hiland Partners 3,000.0 16.0 01/2015 EnLink Midstream Partners, LP and EnLink Midstream, LLC / LPC Crude Oil Marketing LLC 100.0 8.0 11/2013 Tesoro Logistics LP / Remaining portion of logistics assets related to Tesoro’s acquisition of BP’s Carson City assets (Tesoro Corporation) 650.0 10.4 09/2013 JP Energy Development / Wildcat Permian Services LLC 210.0 5.1 11/2012 Targa Resources Partners LP / Williston Basin crude oil pipeline and terminal system and natural gas gathering and processing operations (Saddle Butte Pipeline, LLC) 950.0 11.5 Mean 10.1x Median 10.4 Precedent Transactions – Trucking Transaction Date Transaction Value / Announced Acquiror / Target (Seller) Value EBITDA 10/2018 Martin Midstream Partners L.P. / Martin Transport, Inc. (Martin Resource Management Corporation) $135.0 5.7x 04/2018 PBF Logistics / Terminal, rail and trucking assets (Undisclosed and PBF Energy, Inc.) 125.4 6.9 06/2015 Ferrellgas Partners LP / Bridger Logistics, LLC 837.5 8.4 01/2015 EnLink Midstream Partners, LP / LPC Crude Oil Marketing LLC 100.0 8.0 12/2014 Delek Logistics Partners LP / FRANK Thompson Transport 12.0 5.0 06/2014 Rose Rock Midstream, LP / Crude oil trucking assets (Chesapeake Energy) 50.0 5.5 08/2013 Rose Rock Midstream, LP / Crude oil trucking assets (Barcas Field Services LLC) 47.0 5.5 02/2013 Global Partners LP / 60% membership interest in Basin Transload LLC 85.0 5.0 12/2012 NGL Energy Partners LP / Crude oil purchasing and logistics operations (Pecos Gathering & Marketing) 132.4 5.5 11/2012 Inergy Midstream, LP / Rangeland Energy, LLC 425.0 7.2 10/2012 Gibson Energy Inc. / OMNI Energy Services Corp. 445.0 5.5 06/2012 Quality Distribution, Inc. / Wylie Bice Trucking and RM Resources 100.4 7.9 05/2012 NGL Energy Partners LP / High Sierra Energy LP and High Sierra Energy GP, LLC 679.0 6.2 05/2010 Gibson Energy / Crude oil transportation and logistics operation (Taylor) 153.2 7.1 Median 6.0x Mean 6.4 Source: Public filings, Wall street research 115

Preliminary Draft Subject to Change Preliminary Valuation of Bakken Crude Oil Gathering Precedent M&A Transaction Analysis ($ in millions) Summary Results 2019E EBITDA $2.8 Relevant EBITDA Multiple 7.0x - 9.0x Implied Enterprise Value as of December 31, 2019E $19.7 - $25.4 Implied Enterprise Value Range on June 30, 2019E @ 12.5% Discount Rate $19.2 $24.6 Less: Present Value of June 30, 2019E to June 30, 2019E Growth Capital Expenditures @ 12.5% Discount Rate $-- Implied Enterprise Value Range - 2019E EBITDA $19.2 - $24.6 2020E EBITDA $4.4 Relevant EBITDA Multiple 7.0x - 9.0x Implied Enterprise Value as of December 31, 2020E $30.5 - $39.2 Implied Enterprise Value Range on June 30, 2019E @ 12.5% Discount Rate $27.1 $34.9 Less: Present Value of June 30, 2019E to June 30, 2020E Growth Capital Expenditures @ 12.5% Discount Rate $-- Implied Enterprise Value Range - 2020E EBITDA $27.1 - $34.9 Implied Enterprise Value Range $19.2 $34.9 116 Preliminary Draft Subject to Change Preliminary Valuation of Bakken Crude Oil Gathering Peer Group Trading Analysis ($ in millions, except per unit amounts) Price Equity Enterprise Enterprise Value / EBITDA Distribution Yield Distribution Total Partnership / Corporation 3/7/19 Value Value 2019E 2020E Current 2019E Growth Return Crude Oil Gathering Delek Logistics Partners, LP $32.15 $800.7 $1,496.6 7.9x 7.0x 10.1% 10.7% 3.0% 13.0% Genesis Energy, L.P. 21.63 2,650.5 6,834.2 9.8 9.3 10.0% 10.2% 0.5% 10.4% NGL Energy Partners LP 13.18 1,636.4 4,234.2 8.7 7.9 11.8% 11.8% 1.9% 13.7% Plains All American Pipeline, L.P. 23.97 17,416.1 28,851.1 10.5 10.4 5.0% 5.5% 9.6% 14.6% Mean 9.2x 8.6x 9.2% 9.5% 3.7% 12.9% Median 9.3 8.6 10.0% 10.4% 2.4% 13.4% Summary Results 2019E EBITDA $2.8 Relevant EBITDA Multiple 8.0x - 10.0x Implied Enterprise Value Based on 2019E EBITDA $22.5 - $28.2 2020E EBITDA $4.4 Relevant EBITDA Multiple 7.5x - 9.5x Implied Enterprise Value Based on 2020E EBITDA $32.7 - $41.4 117

Preliminary Draft Subject to Change H. Preliminary Valuation of Silver Dollar Pipeline Preliminary Draft Subject to Change Preliminary Valuation of Silver Dollar Pipeline Summary Valuation ($ in millions) Peer Trading Analysis Peer Trading Analysis Discounted Cash Flow Analysis Precedent M&A Analysis 2019E 2020E $350.0 $300.0 $250.0 $200.0 $183.1 $183.2 $150.0 $135.5 $147.3 $144.7 $100.0 $99.6 $79.7 $50.0 $56.3 $-- 9.5% – 10.5% WACC 2019E and 2020E Multiple Range Selected 2019E Multiple Range Selected 2020E Multiple Range Selected 2023E EBITDA Perpetuity Growth 2019E EBITDA 2020E EBITDA 2019E EBITDA 2020E EBITDA Multiple: Rate: Multiple Multiple Multiple Multiple 7.0x – 9.0x 1.75% – 2.25% 7.0x – 9.0x 7.0x – 9.0x 8.0x – 10.0x 7.5x – 9.5x 118

Preliminary Draft Subject to Change Preliminary Valuation of Silver Dollar Pipeline Discounted Cash Flow Analysis – Assumptions Evercore utilized the following assumptions to analyze Silver Dollar Pipeline’s discounted cash flows: Discounted the projected cash flows to June 30, 2019 EBITDA and capital expenditures through December 31, 2023E per the AMID Financial Projections, assuming no asset sales Unitholder effective tax rate of 29.6% (80.0% of taxable income at 37.0% tax bracket) Mid-point discount rate of 10.0% utilizing WACC based on CAPM Terminal value based on a (i) 7.0x to 9.0x EBITDA exit multiple and (ii) 1.75% to 2.25% perpetuity growth rate Tax depreciation assumed to equal maintenance capital expenditures in perpetuity 119 Preliminary Draft Subject to Change Preliminary Valuation of Silver Dollar Pipeline Discounted Cash Flow Analysis ($ in millions) AMID Financial Projections For the Six Months Ending December 31, For the Years Ending December 31, EBITDA Perpetuity 2019E 2020E 2021E 2022E 2023E Multiple Growth EBITDA $6.2 $19.3 $22.0 $22.1 $22.7 $22.7 $22.7 Less: Tax Depreciation and Amortization (176.3) (13.1) (0.5) (0.4) (0.3) (0.4) EBIT ($170.1) $6.2 $21.5 $21.7 $22.4 $22.3 Less: Cash Taxes -- (0.3) (1.0) (1.0) (1.1) (8.3) EBIAT ($170.1) $5.9 $20.5 $20.6 $21.4 $14.1 Plus: Tax Depreciation and Amortization 176.3 13.1 0.5 0.4 0.3 0.4 Less: Growth Capital Expenditures (12.0) (12.6) -- -- -- --Less: Maintenance Capital Expenditures (0.2) (0.5) (0.5) (0.4) (0.4) (0.4) Unlevered Free Cash Flow ($6.1) $5.9 $20.5 $20.6 $21.3 $14.1 EBITDA Multiple / Perpetuity Growth Rate 8.0x 2.0% Terminal Value $181.9 $179.4 PV of Terminal Value @ 10.0% Discount Rate $118.5 $116.8 Plus: PV of Unlevered Free Cash Flow @ 10.0% Discount Rate 46.4 Implied Enterprise Value $164.8 $163.2 Sensitivity Analysis EBITDA Multiple Perpetuity Growth Rate 6.0x 7.0x 8.0x 9.0x 10.0x 1.75% 1.75% 2.00% 2.25% 2.25% 9.0% $140.3 $155.7 $171.1 $186.6 $202.0 9.0% $181.7 $181.7 $186.8 $192.3 $192.3 ACC 9.5% 137.7 152.8 167.9 183.1 198.2 ACC 9.5% 169.8 169.8 174.2 178.9 178.9 W 10.0% 135.2 150.0 164.8 179.6 194.5 W 10.0% 159.4 159.4 163.2 167.3 167.3 10.5% 132.8 147.3 161.8 176.3 190.8 10.5% 150.1 150.1 153.5 157.0 157.0 11.0% 130.4 144.6 158.8 173.1 187.3 11.0% 141.9 141.9 144.8 147.9 147.9 120

Preliminary Draft Subject to Change Preliminary Valuation of Silver Dollar Pipeline Precedent M&A Transaction Analysis ($ in millions) Precedent Transactions – Crude Oil Gathering Transaction Date Transaction Value / Announced Acquiror / Target (Seller) Value EBITDA 06/2017 Noble Midstream Partners LP / Additional interest in gathering assets in Delaware and DJ Basins (Noble Energy) $270.0 8.7x 06/2017 Howard Energy Partners / Delaware Basin crude oil gathering and natural gas assets (WPX Energy Inc.) 863.0 10.8 08/2016 PBF Logistics / San Joaquin Valley Pipeline (PBF Energy) 175.0 8.8 05/2015 Summit Midstream Partners, LP / Crude oil and produced water gathering systems and transmission pipelines in the Bakken (Summit Midstream Partners, LLC) 255.0 11.4 01/2015 Kinder Morgan, Inc. / Hiland Partners 3,000.0 16.0 01/2015 EnLink Midstream Partners, LP and EnLink Midstream, LLC / LPC Crude Oil Marketing LLC 100.0 8.0 11/2013 Tesoro Logistics LP / Remaining portion of logistics assets related to Tesoro’s acquisition of BP’s Carson City assets (Tesoro Corporation) 650.0 10.4 09/2013 JP Energy Development / Wildcat Permian Services LLC 210.0 5.1 11/2012 Targa Resources Partners LP / Williston Basin crude oil pipeline and terminal system and natural gas gathering and processing operations (Saddle Butte Pipeline, LLC) 950.0 11.5 Mean 10.1x Median 10.4 Precedent Transactions – Trucking Transaction Date Transaction Value / Announced Acquiror / Target (Seller) Value EBITDA 10/2018 Martin Midstream Partners L.P. / Martin Transport, Inc. (Martin Resource Management Corporation) $135.0 5.7x 04/2018 PBF Logistics / Terminal, rail and trucking assets (Undisclosed and PBF Energy, Inc.) 125.4 6.9 06/2015 Ferrellgas Partners LP / Bridger Logistics, LLC 837.5 8.4 01/2015 EnLink Midstream Partners, LP / LPC Crude Oil Marketing LLC 100.0 8.0 12/2014 Delek Logistics Partners LP / FRANK Thompson Transport 12.0 5.0 06/2014 Rose Rock Midstream, LP / Crude oil trucking assets (Chesapeake Energy) 50.0 5.5 08/2013 Rose Rock Midstream, LP / Crude oil trucking assets (Barcas Field Services LLC) 47.0 5.5 02/2013 Global Partners LP / 60% membership interest in Basin Transload LLC 85.0 5.0 12/2012 NGL Energy Partners LP / Crude oil purchasing and logistics operations (Pecos Gathering & Marketing) 132.4 5.5 11/2012 Inergy Midstream, LP / Rangeland Energy, LLC 425.0 7.2 10/2012 Gibson Energy Inc. / OMNI Energy Services Corp. 445.0 5.5 06/2012 Quality Distribution, Inc. / Wylie Bice Trucking and RM Resources 100.4 7.9 05/2012 NGL Energy Partners LP / High Sierra Energy LP and High Sierra Energy GP, LLC 679.0 6.2 05/2010 Gibson Energy / Crude oil transportation and logistics operation (Taylor) 153.2 7.1 Median 6.0x Mean 6.4 Source: Public filings, Wall street research 121 Preliminary Draft Subject to Change Preliminary Valuation of Silver Dollar Pipeline Precedent M&A Transaction Analysis ($ in millions) Summary Results 2019E EBITDA $10.0 Relevant EBITDA Multiple 7.0x - 9.0x Implied Enterprise Value as of December 31, 2019E $69.7 - $89.7 Implied Enterprise Value Range on June 30, 2019E @ 10.0% Discount Rate $68.1 $87.6 Less: Present Value of June 30, 2019E to December 31, 2019E Growth Capital Expenditures @ 10.0% Discount Rate ($11.8) Implied Enterprise Value Range - 2019E EBITDA $56.3 - $75.8 2020E EBITDA $19.3 Relevant EBITDA Multiple 7.0x - 9.0x Implied Enterprise Value as of December 31, 2020E $135.0 - $173.6 Implied Enterprise Value Range on June 30, 2019E @ 10.0% Discount Rate $122.7 $157.8 Less: Present Value of June 30, 2019E to December 31, 2020E Growth Capital Expenditures @ 10.0% Discount Rate ($22.4) Implied Enterprise Value Range - 2020E EBITDA $100.4 - $135.5 Implied Enterprise Value Range $56.3 $135.5 122

Preliminary Draft Subject to Change Preliminary Valuation of Silver Dollar Pipeline Peer Group Trading Analysis ($ in millions, except per unit amounts) Price Equity Enterprise Enterprise Value / EBITDA Distribution Yield Distribution Total Partnership / Corporation 3/7/19 Value Value 2019E 2020E Current 2019E Growth Return Crude Oil Gathering Delek Logistics Partners, LP $32.15 $800.7 $1,496.6 7.9x 7.0x 10.1% 10.7% 3.0% 13.0% Genesis Energy, L.P. 21.63 2,650.5 6,834.2 9.8 9.3 10.0% 10.2% 0.5% 10.4% NGL Energy Partners LP 13.18 1,636.4 4,234.2 8.7 7.9 11.8% 11.8% 1.9% 13.7% Plains All American Pipeline, L.P. 23.97 17,416.1 28,851.1 10.5 10.4 5.0% 5.5% 9.6% 14.6% Mean 9.2x 8.6x 9.2% 9.5% 3.7% 12.9% Median 9.3 8.6 10.0% 10.4% 2.4% 13.4% Summary Results 2019E EBITDA $10.0 Relevant EBITDA Multiple 8.0x - 10.0x Implied Enterprise Value Based on 2019E EBITDA $79.7 - $99.6 2020E EBITDA $19.3 Relevant EBITDA Multiple 7.5x - 9.5x Implied Enterprise Value Based on 2020E EBITDA $144.7 - $183.2 Source: FactSet, Public filings 123 Preliminary Draft Subject to Change I. Preliminary Valuation of Cushing Terminal

Preliminary Draft Subject to Change Preliminary Valuation of Cushing Terminal Summary Valuation ($ in millions) Discounted Cash Flow Analysis Precedent M&A Analysis Peer Trading Analysis $100.0 $75.0 $50.0 $42.7 $40.7 $35.9 $31.7 $32.5 $31.4 $25.0 $-- 10.0% – 11.0% WACC 2020E Multiple Range Selected 2020E Multiple Range Selected 2023E EBITDA Perpetuity Growth 2020E EBITDA 2020E EBITDA Multiple: Rate: Multiple Multiple 8.0x – 10.0x 1.75% – 2.25% 8.0x – 10.0x 7.0x – 8.0x 124 Preliminary Draft Subject to Change Preliminary Valuation of Cushing Terminal Discounted Cash Flow Analysis – Assumptions Evercore utilized the following assumptions to analyze Cushing Terminal‘s discounted cash flows: Discounted the projected cash flows to June 30, 2019 EBITDA and capital expenditures through December 31, 2023E per the AMID Financial Projections, assuming no asset sales Unitholder effective tax rate of 29.6% (80.0% of taxable income at 37.0% tax bracket) Mid-point discount rate of 10.5% utilizing WACC based on CAPM Terminal value based on a (i) 8.0x to 10.0x EBITDA exit multiple and (ii) 1.75% to 2.25% perpetuity growth rate Tax depreciation assumed to equal maintenance capital expenditures in perpetuity 125

Preliminary Draft Subject to Change Preliminary Valuation of Cushing Terminal Discounted Cash Flow Analysis ($ in millions) AMID Financial Projections For the Six Months Ending December 31, For the Years Ending December 31, EBITDA Perpetuity 2019E 2020E 2021E 2022E 2023E Multiple Growth EBITDA ($0.1) $4.5 $4.5 $4.5 $4.5 $4.5 $4.5 Less: Tax Depreciation and Amortization (36.5) -- -- -- -- (0.2) 1 EBIT ($36.6) $4.5 $4.5 $4.5 $4.5 $4.3 Less: Cash Taxes -- (0.2) (0.2) (0.2) (0.2) (1.6) EBIAT ($36.6) $4.3 $4.3 $4.3 $4.3 $2.7 Plus: Tax Depreciation and Amortization 36.5 -- -- -- -- --Less: Growth Capital Expenditures -- -- -- -- -- --Less: Maintenance Capital Expenditures -- -- -- -- -- --Unlevered Free Cash Flow ($0.1) $4.3 $4.3 $4.3 $4.3 $2.7 EBITDA Multiple / Perpetuity Growth Rate 9.0x 2.0% Terminal Value $40.4 $32.3 PV of Terminal Value @ 10.5% Discount Rate $25.8 $20.6 Plus: PV of Unlevered Free Cash Flow @ 10.5% Discount Rate 13.3 Implied Enterprise Value $39.1 $33.9 Sensitivity Analysis EBITDA Multiple Perpetuity Growth Rate 7.0x 8.0x 9.0x 10.0x 11.0x 1.75% 1.75% 2.00% 2.25% 2.25% 9.5% $34.5 $37.5 $40.5 $43.5 $46.5 9.5% $37.1 $37.1 $37.9 $38.8 $38.8 ACC 10.0% 34.0 36.9 39.8 42.7 45.7 ACC 10.0% 35.1 35.1 35.8 36.6 36.6 W 10.5% 33.4 36.3 39.1 42.0 44.9 W 10.5% 33.3 33.3 33.9 34.6 34.6 11.0% 32.8 35.7 38.5 41.3 44.1 11.0% 31.7 31.7 32.2 32.8 32.8 11.5% 32.3 35.1 37.8 40.6 43.3 11.5% 30.2 30.2 30.7 31.3 31.3 1. Assumes maintenance capital expenditures equal to 5.0% of EBITDA 126 Preliminary Draft Subject to Change Preliminary Valuation of Cushing Terminal Precedent M&A Transaction Analysis ($ in millions) Precedent Transactions – Terminals Date Transaction EBITDA Announced Acquiror / Target (Seller) Value Multiple ArcLight Capital Partners, LLC / Two refined products and crude oil terminals located in Tacoma, WA and Baltimore, MD (Targa 09/2018 $160.0 9.6x Resources Corp.) Delek Logistics Partners, LP / Big Spring Logistics assets including 15 storage tanks, salt wells, 4 light products terminals and certain 02/2018 315.0 7.9 other logistics assets (Delek US) 11/2017 TransMontaigne Partners / Martinez and Richmond Terminals (Plains All American) 275.0 10.0 11/2017 Andeavor Logistics LP / Anacortes Logistics Assets (Andeavor) 445.0 8.5 International-Matex Tank Terminals / Epic Midstream, which operates a portfolio of seven terminals in the U.S. Southeast and 08/2017 171.5 11.0 Southwest with 3.1 MMBbls of refined petroleum, asphalt, biofuels and chemical storage capacity (White Deer Energy and Blue Water 06/2017 SemGroup Corporation / Houston Fuel Oil Terminal Company (Alinda Capital Partners) 2,100.0 18.3 04/2017 PBF Logistics LP / Toledo, Ohio, refined products terminal assets (Sunoco Logistics LP) 10.0 3.4 03/2017 Sprague Resources LP / Inwood and Lawrence, New York, terminal assets (Carbo Industries, Inc. and Carbo Realty, L.L.C.) 70.0 7.8 02/2017 Sprague Resources LP / Refined product terminal assets in Springfield, Massachusetts (Leonard E. Belcher, Inc.) 20.0 5.7 01/2017 Sprague Resources LP / Storage terminal and Wilkesbarre Pier in East Providence, Rhode Island (Capital Terminal Company) 23.0 3.8 01/2017 Tallgrass Energy Partners, LP / Tallgrass Terminals, LLC and Tallgrss NatGas Operator, LLC 140.0 8.0 12/2016 NGL Energy Partners LP / Port Hudson Terminal and Kingfisher Facility (Murphy Energy Corporation) 51.0 5.0 11/2016 Tesoro Logistics L.P. / Northern California terminalling and storage assets (Tesoro Corporation) 400.0 8.4 NuStar Energy L.P. / Crude oil and refined products storage terminal in the Port of Corpus Christi, Texas (Martin Midstream Partners 10/2016 93.0 7.0 LP) 10/2016 Phillips 66 Partners / 30 crude oil, refined products and natural gas liquids logistics assets (Phillips 66) 1,300.0 8.7 Western Refining Logistics / Certain terminalling, storage and other logistics assets (Western Refining Inc. / St. Paul Park Refining 09/2016 210.0 8.5 Co.) 08/2016 Valero Energy Partners / Meraux and Three Rivers Terminal services business (Valero Energy Corp.) 325.0 8.3 VTTI Energy Partners LP / Additional 8.4% equity interest in VTTI MLP B.V. and associated pro-rata net debt (VTTI MLP Partners 08/2016 140.0 8.6 B.V.) Tesoro Logistics LP / Alaska crude oil, feedstock and refined product storage tanks and refined product terminals (Tesoro 07/2016 444.0 8.7 Corporation) 03/2016 Valero Energy Partners LP / McKee Terminal Services Business (Valero Energy Corporation) 240.0 8.6 02/2016 Phillips 66 Partners LP / 25% Controlling Interest in Phillips 66 Sweeny Frac LLC (Phillips 66) 236.0 9.7 02/2016 PBF Logistics LP / Four refined products terminals located near Philadelphia, Pennsylvania (Plains All American Pipeline, L.P.) 105.0 7.0 All Transactions Mean 8.2x Median 8.4 Source: Public filings, Wall street research 127

Preliminary Draft Subject to Change Preliminary Valuation of Cushing Terminal Precedent M&A Transaction Analysis ($ in millions) Summary Results 2020E EBITDA $4.5 Relevant EBITDA Multiple 8.0x - 10.0x Implied Enterprise Value as of December 31, 2020E $35.9 - $44.9 Implied Enterprise Value Range on June 30, 2019E @ 10.5% Discount Rate $32.5 $40.7 Less: Present Value of June 30, 2019E to December 31, 2020E Growth Capital Expenditures @ 10.5% Discount Rate $-- Implied Enterprise Value Range - 2020E EBITDA $32.5 - $40.7 128 Preliminary Draft Subject to Change Preliminary Valuation of Cushing Terminal Peer Group Trading Analysis ($ in millions, except per unit amounts) Price Equity Enterprise Enterprise Value / EBITDA Distribution Yield Distribution Total Partnership 3/7/19 Value Value 2019E 2020E Current 2019E Growth Return Crude Oil Storage Blueknight Energy Partners, L.P. $1.14 $46.8 $570.4 8.9x 7.8x 28.1% 24.6% 3.0% 31.1% Global Partners LP 19.10 653.7 1,785.2 8.0 7.8 10.5% 10.6% 3.7% 14.1% Sprague Resources LP 15.30 347.8 944.7 7.8 7.2 17.5% 17.5% 0.3% 17.7% USD Partners LP 11.10 300.6 499.7 8.0 NM 13.0% 13.4% NM NM Mean 8.2x 7.6x 17.2% 16.5% 2.3% 21.0% Median 8.0 7.8 15.2% 15.4% 3.0% 17.7% Summary Results 2020E EBITDA $4.5 Relevant EBITDA Multiple 7.0x - 8.0x Implied Enterprise Value Based on 2020E EBITDA $31.4 - $35.9 Implied Enterprise Value $31.4 - $35.9 Source: FactSet, Public Filings 129

Preliminary Draft Subject to Change J. Preliminary Valuation of NGL JV Interests Preliminary Draft Subject to Change Preliminary Valuation of NGL JV Interests Summary Valuation ($ in millions) Peer Trading Analysis Peer Trading Analysis Discounted Cash Flow Analysis Precedent M&A Analysis 2019E 2020E $250.0 $198.7 $200.0 $179.7 $181.9 $163.6 $168.1 $150.0 $150.2 $145.8 $129.8 $100.0 $50.0 8.0% – 9.0% WACC 2019E and 2020E Multiple Range Selected 2019E Multiple Range Selected 2020E Multiple Range Selected 2023E EBITDA Perpetuity Growth 2019E EBITDA 2020E EBITDA 2019E EBITDA 2020E EBITDA Multiple: Rate: Multiple Multiple Multiple Multiple 10.0x – 12.0x 1.75% – 2.25% 10.0x – 12.0x 10.0x – 12.0x 11.0x – 13.0x 9.5x – 11.5x 130

Preliminary Draft Subject to Change Preliminary Valuation of NGL JV Interests Discounted Cash Flow Analysis – Assumptions Evercore utilized the following assumptions to perform a discounted cash flow analysis on AMID’s 25.3% interest in Wilprise, 16.7% interest in Tri-State and 50.0% interest in Cayenne: Discounted the projected cash flows to June 30, 2019 EBITDA and capital expenditures through December 31, 2023E per the AMID Financial Projections Unitholder effective tax rate of 29.6% (80.0% of taxable income at 37.0% tax bracket) Mid-point discount rate of 8.5% utilizing WACC based on CAPM Terminal value based on a (i) 10.0x to 12.0x EBITDA exit multiple and (ii) 1.75% to 2.25% perpetuity growth rate Tax depreciation assumed to equal maintenance capital expenditures in perpetuity 131 Preliminary Draft Subject to Change Preliminary Valuation of NGL JV Interests Discounted Cash Flow Analysis ($ in millions) AMID Financial Projections For the Six Months Ending December 31, For the Years Ending December 31, EBITDA Perpetuity 2019E 2020E 2021E 2022E 2023E Multiple Growth EBITDA $5.2 $15.8 $15.4 $14.2 $13.2 $13.2 $13.2 Less: Tax Depreciation and Amortization (146.6) -- -- -- -- --EBIT ($141.4) $15.8 $15.4 $14.2 $13.2 $13.2 Less: Cash Taxes -- (0.7) (0.7) (0.7) (0.6) (4.9) EBIAT ($141.4) $15.1 $14.6 $13.5 $12.6 $8.3 Plus: Tax Depreciation and Amortization 146.6 -- -- -- -- --Less: Growth Capital Expenditures -- -- -- -- -- --Less: Maintenance Capital Expenditures -- -- -- -- -- --Unlevered Free Cash Flow $5.2 $15.1 $14.6 $13.5 $12.6 $8.3 EBITDA Multiple / Perpetuity Growth Rate 11.0x 2.0% Terminal Value $145.2 $130.5 PV of Terminal Value @ 8.5% Discount Rate $100.6 $90.4 Plus: PV of Unlevered Free Cash Flow @ 8.5% Discount Rate 51.1 Implied Enterprise Value $151.7 $141.5 Sensitivity Analysis EBITDA Multiple Perpetuity Growth Rate 9.0x 10.0x 11.0x 12.0x 13.0x 1.50% 1.75% 2.00% 2.25% 2.50% 7.5% $137.9 $147.4 $157.0 $166.5 $176.0 7.5% $153.7 $158.4 $163.5 $169.1 $175.2 ACC 8.0% 135.6 145.0 154.3 163.6 173.0 ACC 8.0% 143.4 147.4 151.6 156.2 161.2 W 8.5% 133.4 142.5 151.7 160.8 170.0 W 8.5% 134.6 137.9 141.5 145.3 149.5 9.0% 131.2 140.2 149.1 158.1 167.0 9.0% 127.0 129.8 132.8 136.1 139.6 9.5% 129.1 137.9 146.6 155.4 164.2 9.5% 120.3 122.7 125.3 128.1 131.1 132

Preliminary Draft Subject to Change Preliminary Valuation of NGL JV Interests Precedent M&A Transaction Analysis ($ in millions) Precedent Transactions – NGL Transportation Transaction Date Transaction Value / Announced Acquiror / Target (Seller) Value EBITDA 10/2017 Blackstone Energy Partners / 25% interest in Grand Prix Pipeline (Targa Resources Corp) $325.0 10.0x 10/2016 Phillips 66 Partners LP / 30 Crude, Products, and NGL Logistics Assets (Phillips 66) 1,300.0 8.7 6/2016 Riverstone Investment Group LLC / 50% Partner Interest in Utopia Pipeline Project (Kinder Morgan, Inc.) 300.0 12.0 5/2016 Phillips 66 Partners LP / Standish Pipeline and remaining 75% in Phillips 66 Sweeny Frac LLC (Phillips 66) 775.0 8.6 2/2015 Phillips 66 Partners LP / Interests in LLCs owning Sand Hills NGL pipelines and Explorer refined products pipeline (Phillips 66) 1,077.6 9.5 2/2015 NGL Energy Partners LP / NGL Storage Facility (Magnum NGLs LLC) 280.0 10.5 10/2014 ONEOK Partners, LP / 80% interest in WTLPG and 100% interest in Mesquite Pipeline (Chevron Corporation) 800.0 20.0 9/2014 Boardwalk Pipeline Partners, LP / Evangeline ethylene pipeline system (Chevron Petrochemical Pipeline LLC) 295.0 12.5 9/2014 Pembina Pipeline Corporation / Vantage Pipeline System and Mistral Midstream Inc.‘s interest in the Saskatchewan Ethane Extraction Plant (Riverstone Holdings LLC) 650.0 12.5 5/2014 Martin Midstream Partners LP / 20% interest in West Texas LPG Pipeline LP (Atlas Pipeline NGL Holdings, LLC) 134.4 14.5 DCP Midstream Partners, LP / 33.3% interest in each of Sand Hills and Southern Hills pipelines, remaining 20% interest in Eagle Ford system and the Lucerne 1 gas processing 2/2014 plant (DCP Midstream, LP) 1,150.0 12.0 2/2014 Western Gas Partners, LP / 20% interest in Texas Express Pipeline LLC and Texas Express Gathering LLC and a 33.3% interest in Front Range Pipeline LLC (Anadarko) 375.0 11.1 2/2014 Phillips 66 Partners LP / Gold Product Pipeline System and Medford Spheres (Phillips 66) 700.0 10.4 8/2013 DCP Midstream Partners, LP / 33.3% interest in Front Range Pipeline LLC (DCP Midstream, LP) 86.0 15.0 4/2011 Atlas Pipeline Partners LP / 20% interest in West Texas LPG Limited Partnership (Buckeye Partners, LP) 85.0 13.7 3/2011 Energy Transfer Partners, LP and Regency Energy Partners LP / Louis Dreyfus Highbridge Energy LLC 1,925.0 11.6 All Transactions Median 11.8x Mean 12.0 Source: Public filings, Wall street research 133 Preliminary Draft Subject to Change Preliminary Valuation of NGL JV Interests Precedent M&A Transaction Analysis ($ in millions) Summary Results 2019E EBITDA $15.3 Relevant EBITDA Multiple 10.0x - 12.0x Implied Enterprise Value as of December 31, 2019E $152.9 - $183.4 Implied Enterprise Value Range on June 30, 2019E @ 8.5% Discount Rate $149.8 $179.7 Less: Present Value of June 30, 2019E to December 31, 2019E Growth Capital Expenditures @ 8.5% Discount Rate $-- Implied Enterprise Value Range - 2019E EBITDA $149.8 - $179.7 2020E EBITDA $15.8 Relevant EBITDA Multiple 10.0x - 12.0x Implied Enterprise Value as of December 31, 2020E $158.1 - $189.8 Implied Enterprise Value Range on June 30, 2019E @ 8.5% Discount Rate $145.8 $174.9 Less: Present Value of June 30, 2019E to December 31, 2020E Growth Capital Expenditures @ 8.5% Discount Rate $-- Implied Enterprise Value Range - 2020E EBITDA $145.8 - $174.9 Implied Enterprise Value Range $145.8 $179.7 134

Preliminary Draft Subject to Change Preliminary Valuation of NGL JV Interests Peer Group Trading Analysis ($ in millions, except per unit / share amounts) Price Equity Enterprise Enterprise Value / EBITDA Distribution Yield Distribution Total Partnership / Corporation 3/7/19 Value Value 2019E 2020E Current 2019E Growth Return Enterprise Products Partners L.P. $28.22 $61,657.1 $87,929.2 11.8x 11.1x 6.2% 6.3% 2.6% 8.7% ONEOK, Inc. 65.89 27,121.1 36,490.1 13.9 11.6 5.2% 5.4% 9.6% 14.8% Phillips 66 Partners LP 50.68 6,417.9 10,210.9 8.4 7.2 6.6% 6.8% 4.9% 11.5% Targa Resources Corp. 40.09 9,306.6 15,929.7 12.8 10.2 9.1% 9.1% 3.3% 12.3% Mean 11.7x 10.0x 6.8% 6.9% 5.1% 11.8% Median 12.3 10.7 6.4% 6.6% 4.1% 11.9% Summary Results 2019E EBITDA $15.3 Relevant EBITDA Multiple 11.0x - 13.0x Implied Enterprise Value Based on 2019E EBITDA $168.1 - $198.7 2020E EBITDA $15.8 Relevant EBITDA Multiple 9.5x - 11.5x Implied Enterprise Value Based on 2020E EBITDA $150.2 - $181.9 Source: FactSet, Public filings 135 Preliminary Draft Subject to Change K. Preliminary Valuation of AMID Corporate G&A Expenses

Preliminary Draft Subject to Change Preliminary Valuation of AMID Corporate G&A Expenses Summary Valuation ($ in millions) Peer Trading Analysis Discounted Cash Flow Analysis Precedent M&A Analysis 2019E 2020E $600.0 $583.1 $550.0 $513.2 $508.9 $500.0 $492.2 $483.1 $450.0 $422.9 $400.0 $399.1 $350.0 $336.3 $300.0 $250.0 $200.0 8.4% – 9.4% WACC 2019E and 2020E Multiple Range Selected 2019E Multiple Range Selected 2020E Multiple Range Selected 2023E EBITDA Perpetuity Growth 2019E EBITDA 2020E EBITDA 2019E EBITDA 2020E EBITDA Multiple: Rate: Multiple Multiple Multiple Multiple 8.8x – 10.6x 1.75% – 2.25% 7.4x – 9.3x 7.4x – 9.3x 8.8x – 10.6x 8.0x – 9.9x 136 Preliminary Draft Subject to Change Preliminary Valuation of AMID Corporate G&A Expenses Discounted Cash Flow Analysis – Assumptions Evercore utilized the following assumptions to perform a discounted cash flow analysis on AMID’s corporate G&A expenses Discounted the projected cash flows to June 30, 2019 Corporate G&A expenses per AMID Financial Projections Unitholder effective tax rate of 29.6% (80.0% of taxable income at 37.0% tax bracket) Mid-point discount rate of 8.9% utilizing weighted average WACC used in Sum of the Parts Analysis Terminal value based on a (i) 8.8x to 10.6x EBITDA exit multiple based on weighted average peer trading multiple and (ii) 1.75% to 2.25% perpetuity growth rate Based on weighted average of EBITDA exit multiple and perpetuity growth rate used in the Sum of the Parts analysis 137

Preliminary Draft Subject to Change Preliminary Valuation of AMID Corporate G&A Expenses Discounted Cash Flow Analysis ($ in millions) AMID Financial Projections For the Six Months Ending December 31, For the Years Ending December 31, Perpetuity 2019E 2020E 2021E 2022E 2023E Multiple Growth Corporate G&A Expense $26.7 $49.8 $49.8 $49.8 $49.8 $49.8 $49.8 Corporate G&A Expense $26.7 $49.8 $49.8 $49.8 $49.8 $49.8 Less: Cash Taxes (6.3) (11.8) (11.8) (11.8) (11.8) (18.4) Unlevered Free Cash Flow $20.4 $38.0 $38.0 $38.0 $38.0 $31.4 Multiple / Perpetuity Growth Rate 9.7x 2.0% Terminal Value $483.1 $466.9 PV of Terminal Value @ 8.9% Discount Rate $329.8 $318.7 Plus: PV of Unlevered Free Cash Flow @ 8.9% Discount Rate 143.5 Implied Value of AMID Corporate G&A Liability $473.3 $462.2 Sensitivity Analysis EBITDA Multiple Perpetuity Growth Rate 7.8x 8.8x 9.7x 10.6x 11.6x 1.50% 1.75% 2.00% 2.25% 2.50% 7.9% $422.4 $457.8 $490.1 $522.3 $557.8 7.9% $502.9 $518.5 $535.3 $553.7 $573.7 ACC 8.4% 415.3 450.0 481.6 513.2 547.9 ACC 8.4% 468.7 481.8 495.9 511.2 527.7 W 8.9% 408.4 442.4 473.3 504.2 538.2 W 8.9% 439.1 450.3 462.2 475.1 489.0 9.4% 401.6 434.9 465.2 495.5 528.8 9.4% 413.3 422.9 433.1 444.1 455.9 9.9% 395.0 427.6 457.3 487.0 519.6 9.9% 390.5 398.9 407.7 417.2 427.3 138 Preliminary Draft Subject to Change Preliminary Valuation of AMID Corporate G&A Expenses Precedent M&A Transaction and Peer Trading Analysis ($ in millions) Precedent M&A Transaction Summary Results 2019E Corporate G&A Expense $55.0 Relevant Multiple1 7.4x - 9.3x Implied AMID Corporate G&A Liability Based on 2019E Expense $404.0 - $508.9 Implied Enterprise Value Range on June 30, 2019E @ 8.9% Discount Rate $404.0 $508.9 2020E Corporate G&A Expense $49.8 Relevant Multiple1 7.4x - 9.3x Implied AMID Corporate G&A Liability Based on 2020E Expense $366.1 - $461.2 Implied Enterprise Value Range on June 30, 2019E @ 8.9% Discount Rate $336.3 $423.7 Implied Value of AMID Corporate G&A Liability $336.3 $508.9 Peer Trading Summary Results 2019E Corporate G&A Expense $55.0 Relevant Multiple1 8.8x - 10.6x Implied AMID Corporate G&A Liability Based on 2019E Expense $483.1 - $583.1 2020E Corporate G&A Expense $49.8 Relevant Multiple1 8.0x - 9.9x Implied AMID Corporate G&A Liability Based on 2020E Expense $399.1 - $492.2 1. Based on weighted average EBITDA multiple used in the Sum of the Parts analysis excluding Delta House 139